Venture Global - 10-K annual report 2025

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2025

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to .

Commission file number 001-42486

VENTURE GLOBAL, INC.

(Exact Name of Registrant as Specified in Its Charter)

Delaware

95-3539083

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification Number)

1001 19th Street North, Suite 1500

Arlington, Virginia 22209

(Address of Principal Executive Offices)

(202) 759-6740

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

Class A common stock, $ 0.01 par value

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer ☐ Accelerated filer ☐						Smaller reporting company ☐
Non-accelerated filer ☒ (Do not check if a smaller reporting company)						Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the registrant's voting and non‑voting common equity held by non‑affiliates on June 30, 2025, the last business day of its most recently completed second fiscal quarter (based on the closing sale price of $15.58 of the Registrant's Common Stock, as reported by the New York Stock Exchange on such date) was approximately $7.1 billion.

As of February 13, 2026, the number of shares of the registrant’s Class A common stock outstanding was 488,365,847, and the number of shares of the registrant’s Class B common stock outstanding was 1,968,604,458.

DOCUMENTS INCORPORATED BY REFERENCE

Certain portions of the definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) are incorporated by reference into Part III of this Annual Report on Form 10-K. Except with respect to information specifically incorporated by reference in this Annual Report on Form 10-K, such proxy statement will not be deemed to be filed as part hereof.

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			Page
Glossary of Key Terms			1
Cautionary Statement Regarding Forward-Looking Statements			5
Summary of Material Risks Associated with Our Business			8
PART I
Item 1. Business			10
Item 1A. Risk Factors			33
Item 1B. Unresolved Staff Comments			96
Item 1C. Cybersecurity			96
Item 2. Properties			98
Item 3. Legal Proceedings			98
Item 4. Mine Safety Disclosure			101
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			102
Item 6. [Reserved]			103
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			103
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			130
Item 8. Financial Statements and Supplementary Data			132
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			178
Item 9A. Controls and Procedures			178
Item 9B. Other Information			179
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			179
PART III
Item 10. Directors, Executive Officers and Corporate Governance			179
Item 11. Executive Compensation			180
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			180
Item 13. Certain Relationships and Related Transactions and Director Independence			181
Item 14. Principal Accounting Fees and Services			181
PART IV
Item 15. Exhibits and Financial Statements Schedules			181
Item 16. Form 10-K Summary			197
Signatures			198

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GLOSSARY OF KEY TERMS

Unless otherwise indicated or the context otherwise requires, as used in this Form 10-K:

◦Blackfin means Blackfin Pipeline, LLC, a joint venture between the Company, through its wholly-owned subsidiary Venture Global Midstream Holdings, LLC, and WhiteWater Development LLC, which is engaged in the development and construction of the Blackfin Pipeline;

◦Blackfin Credit Facilities means the project financing obtained by Blackfin, consisting of a senior secured term loan facility, or the Blackfin TLB Facility, a senior secured construction term loan facility, or the Blackfin TLA Facility, and a senior secured working capital facility, or the Blackfin Working Capital Facility;

◦Calcasieu Funding means Calcasieu Pass Funding, LLC;

◦Calcasieu Holdings means Calcasieu Pass Holdings, LLC;

◦Calcasieu Pass Credit Facilities means project financing obtained by VGCP consisting of a construction term loan, or the Calcasieu Pass Construction Term Loan, and a working capital facility, or the Calcasieu Pass Working Capital Facility;

◦Class A common stock means our Class A common stock, par value $0.01 per share, entitled to one vote per share;

◦Class B common stock means our Class B common stock, par value $0.01 per share, entitled to ten votes per share;

◦COD means the commercial operations date, which is the first day of commercial operations at a project or a phase of a project, as applicable, as specifically defined in the relevant post-COD SPAs, and which does not occur unless and until: (i) all of the facilities comprising the relevant project, or phase thereof, have been completed and commissioned, including any ramp up period, (ii) the project or phase thereof is capable of delivering LNG in sufficient quantities and necessary quality to perform all of its obligations under such post-COD SPAs, and (iii) the applicable project company has notified the customer under the post-COD SPAs;

◦commercial operations means the production period commencing after the occurrence of COD at a project or a phase of a project, as applicable;

◦commissioning or commissioning phase means, with respect to our LNG projects, the phase of development where our facilities undergo certain required performance and reliability testing, which includes: (i) the sequential start-up and testing of certain key equipment (e.g., liquefaction trains) as it is installed during construction and (ii) the testing and tuning of the full integrated LNG project after all key equipment and modules have passed their individual performance tests;

◦commissioning cargos means the LNG cargos produced by us during the commissioning phase of an LNG project, which commences once a project produces its first quantities of LNG and ends once a project, or phase thereof, achieves COD. Proceeds from the sale of commissioning cargos are recognized in our financial statements as a reduction to the cost basis of construction in progress until assets are placed in service from an accounting perspective, the timing of which may differ from COD. After assets are placed in service from an accounting perspective, the proceeds are recognized through revenue;

◦commodity fees means the volume weighted average portion of the fees associated with LNG sold during a relevant period indexed to Henry Hub;

◦Company, we, our, us or similar terms mean Venture Global, Inc. and its subsidiaries, collectively;

◦Contracted SPAs means post-COD SPAs and Firm-start SPAs.

◦CP Express means Venture Global CP Express, LLC;

◦CP Funding Redeemable Preferred Units means the nine million redeemable preferred units issued by Calcasieu Funding;

◦CP Holdings Convertible Preferred Units means the four million convertible preferred units issued by Calcasieu Holdings;

◦CP2 means Venture Global CP2 LNG, LLC;

◦CP2 Bridge Facilities means the secured bridge credit facilities, consisting of a $2.8 billion bridge loan facility and a $175 million three-year interest reserve facility, entered into by CP2 to fund a portion of project costs for the CP2 Project;

◦CP2 Credit Facilities means project financing obtained by CP2, consisting of a senior secured construction term loan facility, or the CP2 Construction Term Loan, and a senior secured working capital facility, or the CP2 Working Capital Facility;

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◦CP2 EPC Contracts means the Phase 1 and Phase 2 EPC contracts pursuant to which the CP2 Project is being constructed;

◦CP2 Holdings means CP2 LNG Holdings, LLC;

◦CP2 Holdings EBL Facilities means the secured equity bridge credit facilities, consisting of a $2.8 billion secured equity bridge credit facility, and a $191 million three-year secured interest reserve credit facility;

◦CP2 Procurement means CP2 Procurement, LLC;

◦CP3 means Venture Global CP3 LNG, LLC;

◦Currently permitted annualized production capacity means the production levels of LNG at each of our projects which has been authorized by one or more relevant regulatory agencies

◦Delta means Venture Global Delta LNG, LLC;

◦DES means delivered ex ship, which with respect to LNG SPAs, requires the sellers to deliver LNG to a named port;

◦DOE means the United States Department of Energy;

◦DPU means delivered at place unloaded, which, with respect to LNG SPAs, requires the seller to deliver and unload LNG at one or more designated destinations;

◦EMIR means European Market Infrastructure Regulation;

◦EPC means engineering, procurement and construction;

◦EPCM means engineering, procurement, and construction management, which entails certain supervision, management, and co-ordination of EPC and other construction interface work;

◦excess capacity or excess LNG means the amount of LNG that is produced by our liquefaction facilities that is in excess of the nameplate capacity;

◦expected annualized peak production capacity means the anticipated maximum technical post COD-production levels of LNG produced by our liquefaction facilities under optimal operating conditions (e.g., cooler ambient temperatures, peak equipment efficiency, ideal feed-gas composition and minimal downtime) on an annual basis;

◦expected annualized production capacity means the anticipated sustainable post-COD production levels of LNG produced by our liquefaction facilities under normal operating conditions on an annual basis;

◦FERC means the Federal Energy Regulatory Commission;

◦FID means the final investment decision with respect to the development of a project or a phase thereof, which, with respect to an LNG project, requires that the project has secured (i) all of the debt and equity financing arrangements necessary to fully construct, commission, and operate such project or phase thereof and (ii) all of the necessary permits to construct, operate, and export LNG;

◦Firm-start SPAs means SPAs entered into in which the obligation to deliver LNG begins as of a pre-established future date (as opposed to post-COD of a certain project);

◦fixed liquefaction fee means the volume weighted average of the fixed liquefaction fees associated with LNG sold during a relevant period, excluding variable commodity fees;

◦FOB means free on board which, with respect to LNG SPAs, requires the seller to deliver and load LNG onto the buyer's LNG tankers at the seller's export terminal;

◦FTA means a free trade agreement;

◦GAAP means accounting principles generally accepted in the United States;

◦Gator Express means Venture Global Gator Express, LLC;

◦Henry Hub means the final settlement price (in $ per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin;

◦HGEO means U.S. Department of Energy, Hydrocarbons and Geothermal Energy Office;

◦ICC means the International Chamber of Commerce, International Court of Arbitration;

◦intercompany excess capacity SPAs mean SPAs entered into by any of our projects, including the Calcasieu, Plaquemines or CP2 projects, to sell to VG Commodities any excess LNG produced above the nameplate capacity of the respective project, upon achievement of COD for such project;

◦IPO means our initial public offering of Class A common stock, par value $0.01 per share, that we completed on January 27, 2025;

◦JKM means the Japan Korea Marker index for liquefied natural gas in Northeast Asia;

◦KZJV means KZJV, LLC, a limited liability company that is owned by KBR EPC Member and Zachry Industrial, Inc.;

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◦liquefaction train or train means a liquefaction production unit that cools natural gas to a liquid state;

◦LNG means liquefied natural gas, or methane, supercooled to -260°F and converted into a liquid state, which reduces it to 1/600th of its original volume, enabling large quantities of natural gas to be loaded and shipped by LNG tankers;

◦LNG Commissioning Sales Agreements means short- or mid-term sales agreements under which commissioning cargos are sold at prevailing market prices when executed;

◦LNG volumes exported means LNG volumes that departed our LNG facilities;

◦LNG volumes sold means LNG delivered to customers and recognized in results of operations;

◦MMBtu means million British thermal units;

◦mtpa means million tonnes per annum, which is a common unit of measurement for annual LNG production;

◦MW means one million watts, a unit of power;

◦nameplate capacity means, unless the context otherwise requires, the conservative measure of LNG production capability, based on vendor guaranteed LNG output of each of our facilities;

◦natural gas means any hydrocarbons that are gaseous at standard temperature and pressure;

◦natural gas supply contracts means natural gas forward purchase contracts for the supply of feed gas to our projects;

◦NPNS means normal purchases and normal sales scope exception, a rule under GAAP;

◦Omnibus Incentive Plan means the Venture Global, Inc. 2025 Omnibus Incentive Plan;

◦Plaquemines Credit Facilities means project financing obtained by VGPL consisting of a term loan facility, or the Plaquemines Construction Term Loan, and a working capital revolving facility, or the Plaquemines Working Capital Facility;

◦Plaquemines EPC Contracts means the Phase 1 and Phase 2 EPC contracts pursuant to which the Plaquemines Project is being constructed;

◦post-COD SPA means an SPA for the sale and purchase of LNG after COD has occurred for a particular project or phase thereof;

◦projects means our existing and proposed LNG facilities and related assets, including the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project and any bolt-on expansions to such projects, including the Plaquemines Expansion Project and the CP2 Expansion Project.

◦regasification means the process of heating LNG to convert it from a liquid to gaseous state after the LNG is offloaded from an LNG carrier;

◦REMIT means Regulation on wholesale Energy Market Integrity and Transparency;

◦Repsol means Repsol LNG Holding, S.A.;

◦Sales and shipping means our direct sales and shipping business through VG Commodities;

◦SEC means the U.S. Securities and Exchange Commission;

◦Shell means Shell NA LNG LLC;

◦SOFR means the U.S. Secured Overnight Financing Rate;

◦SPA means LNG sales and purchase agreement;

◦TBtu means trillion British thermal units;

◦TCP means TransCameron Pipeline, LLC;

◦Test LNG sales means proceeds from the sale of test LNG generated during the early commissioning of an LNG project;

◦Total Project Cost means the costs to complete a project, including EPC contractor profit and contingency, owners’ costs and financing costs, excluding costs for operations, maintenance, and extended commissioning and start up activities;

◦Trigger Date means the first time at which either (i) VG Partners and its permitted transferees, collectively, no longer beneficially own more than 50% of the combined voting power of our outstanding common stock entitled to vote generally in the election of directors, or (ii) we fail to qualify as a “controlled company” (or similar) under the applicable stock exchange rules;

◦TRIR means total recordable incident rate;

◦TTF means the Title Transfer Facility index for liquefied natural gas in Europe;

◦U.S. means United States of America;

◦Venture Global means Venture Global, Inc., but not its subsidiaries;

◦VG Commodities means Venture Global Commodities, LLC;

◦VG Partners means Venture Global Partners II, LLC, our controlling shareholder;

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◦VGCP means Venture Global Calcasieu Pass, LLC;

◦VGCP Senior Secured Notes means the VGCP 2029 Notes, VGCP 2030 Notes, VGCP 2031 Notes and VGCP 2033 Notes, collectively;

◦VGLNG or Venture Global LNG means Venture Global LNG, Inc.;

◦VGLNG Senior Secured Notes means the VGLNG 2028 Notes, VGLNG 2029 Notes, VGLNG 2030 Notes, VGLNG 2031 Notes and VGLNG 2032 Notes, collectively;

◦VGLNG Series A Preferred Shares means the three million shares of Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock issued by VGLNG;

◦VGLNG Revolving Credit Facility means financing obtained by VGLNG consisting of a $2.0 billion senior secured credit facility;

◦VGPL means Venture Global Plaquemines LNG, LLC;

◦VGPL Senior Secured Notes means the VGPL 2030 Notes, VGPL 2033 Notes, VGPL January 2034 Notes, VGPL June 2034 Notes, VGPL 2035 Notes and VGPL 2036 Notes, collectively;

◦Weighted average price of LNG volumes sold means contracted sales prices, generally consisting of a liquefaction fee and a commodity fee; and

◦Worley means Worley Field Services Inc.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements. We intend such forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements, other than statements of historical facts, included herein are “forward-looking statements.” In some cases, forward-looking statements can be identified by terminology such as “may,” “might,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

These forward-looking statements, which are subject to risks, uncertainties and assumptions about us, may include projections of our future financial performance, expectations regarding the development, construction, commissioning and completion of our projects, estimates of the cost of our projects and schedule to construct and commission our projects, our anticipated growth strategies and anticipated trends impacting our business. These statements are only predictions based on our current expectations and projections about future events. There are important factors that could cause our actual results, level of activity, performance or achievements to differ materially from the results, level of activity, performance or achievements expressed or implied by the forward-looking statements. Those factors include the following:

•our potential inability to maintain profitability, maintain positive operating cash flow and ensure adequate liquidity in the future, including as a result of the significant uncertainty in our ability to generate proceeds and the amount of proceeds that will regularly be received from sales of uncontracted commissioning cargos and excess cargos due to volatility and variability in the LNG markets;

•our need for significant additional capital to construct and complete our projects, including some of our existing projects, future projects, potential bolt-on expansions and related assets, and our potential inability to secure such financing on acceptable terms, or at all;

•our potential inability to construct or operate all of our proposed LNG facilities or pipelines or any additional LNG facilities or pipelines beyond those currently planned, including any of the bolt-on expansion opportunities which we have identified, and to produce LNG in excess of our nameplate capacity, which could limit our growth prospects, including as a result of delays in obtaining regulatory approvals or inability to obtain requisite regulatory approvals to complete construction during our estimated development periods;

•significant operational risks related to our natural gas liquefaction and export projects, including our existing projects and any potential bolt-on expansions, any future projects we develop, our pipelines, our LNG tankers, and our regasification terminal usage rights;

•our potential inability to accurately estimate costs for our projects, and the risk that the construction and operations of natural gas pipelines and pipeline connections for our projects suffer cost overruns and delays related to obtaining regulatory approvals, development risks, labor costs, unavailability of skilled workers, operational hazards and other risks;

•the uncertainty regarding the future of international trade agreements and the United States’ position on international trade, including the effects of tariffs;

•our current and potential involvement in disputes and legal proceedings, including the arbitrations and other proceedings currently pending against us and the possibility and magnitude of negative outcomes in any such dispute or proceeding and the potential impact thereof on our results of operations, liquidity and our existing contracts;

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•our potential inability to enter into the necessary contracts to construct our projects, or any potential bolt-on expansion, on a timely basis or on terms that are acceptable to us;

•our potential inability to enter into Contracted SPAs with customers for, or to otherwise sell, an adequate portion of the total expected nameplate capacity at our existing projects, any potential bolt-on expansions, or any future projects we develop;

•our dependence on our EPC and other contractors and suppliers for the successful completion of our projects and delivery of our LNG tankers, including the potential inability of our contractors to perform their obligations under their contracts;

•various economic and political factors, including opposition by environmental or other public interest groups, or the lack of local government and community support required for our projects, which could negatively affect the permitting status, timing or overall development, construction and operation of our projects;

•the effects of FERC regulation on our interstate natural gas pipelines and their FERC gas tariffs;

•the risk that the natural gas liquefaction system and mid-scale design we utilize at our projects will not achieve the level of performance or other benefits that we anticipate;

•potential additional risks arising from the duration of and the phased commissioning start-up of our projects;

•the potential risk that our customers or we may terminate our SPAs if certain conditions are not met or for other reasons;

•potential decreases in the price of natural gas and its related impact on our ability to pay the cost of gas transportation, the payment of a premium by us for feed gas relative to the contractual price we charge our customers, or other impacts to the price of natural gas resulting from inflationary pressures;

•the potential negative impacts of seasonal fluctuations on our business;

•the risks related to the development and/or contracting for additional gas transportation capacity to support the operation and expansion capacity of our LNG projects;

•the risks related to the management and operation of our LNG tanker fleet and our future regasification terminal usage rights;

•the potential effects of existing and future environmental and similar laws and governmental regulations on compliance costs, operating and/or construction costs and restrictions;

•our potential inability to obtain, maintain or comply with necessary permits or approvals from governmental and regulatory agencies on which the construction of our projects depends, including as a result of opposition by environmental and other public interest groups;

•our indebtedness levels, and the fact that we may be able to incur substantially more indebtedness, which may increase the risks created by our substantial indebtedness; and

•risks related to other factors discussed under Item 1A.—Risk Factors of this Form 10-K.

In addition, new risks emerge from time to time as we operate in a very competitive and rapidly changing business environment. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Given these uncertainties, you should not place undue reliance on these forward-looking statements.

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All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond our control. New factors emerge from time to time, and it is not possible for management to predict all such factors or to assess the impact of each such factor on us.

Any forward-looking statement speaks only as of the date on which such statement is made, and we do not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made except as required by the federal securities laws. If one or more of these or other risks or uncertainties materialize, or if our underlying assumptions prove to be incorrect, our actual results may vary materially from what we may have expressed or implied by these forward-looking statements. We caution that you should not place undue reliance on any of our forward-looking statements. Furthermore, new risks and uncertainties arise from time to time, and it is impossible for us to predict those events or how they may affect us.

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SUMMARY OF MATERIAL RISKS ASSOCIATED WITH OUR BUSINESS

Our business is subject to numerous risks and uncertainties that you should be aware of in evaluating our business. These risks include, but are not limited to, the following:

•Our ability to maintain profitability and positive operating cash flows is subject to significant uncertainty.

•We have only a limited track record and historical financial information, and there is no assurance that our business will be successful over the long term.

•Historical proceeds from commissioning cargo sales at the Calcasieu Project, which had an extended commissioning period due to unanticipated challenges with equipment reliability and which began producing LNG in a high-price environment, may not be indicative of the duration of the commissioning period or the amount of proceeds for any of our other projects or expansions thereof.

•Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds, given significant volatility in spot-market prices.

•Our ability to optimize sales of our LNG cargos is subject to significant uncertainty and volatility in proceeds generated from such sales.

•We have not entered into SPAs with customers for the total expected nameplate capacity at Phase 2 of the CP2 Project, or other future projects or expansions, and our failure to enter into final and binding contracts for an adequate portion of, or to otherwise sell, the expected nameplate capacity of any of our projects, including any phases or expansions thereof, could impact our ability to take FID for such projects.

•Our revenues and operating margins may be adversely affected if we are unable to produce and sell liquefaction capacity in excess of the nameplate capacity of our facilities.

•Our customers or we may terminate our SPAs if certain conditions are not met or for other reasons.

•Our ability to generate cash under our Contracted SPAs and sales by VG Commodities is substantially dependent upon the performance by a limited number of our customers, and we could be materially and adversely affected if certain of these customers fail to perform their contractual obligations for any reason.

•Our operating margins may be adversely affected if the price of natural gas decreases, if we pay a premium for feed gas relative to the contractual spot price we charge our customers, or as a result of inflationary pressures.

•We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

•Our limited diversification could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

•We are dependent on the strategic direction of Michael Sabel, our Chief Executive Officer, Executive Co-Chairman of the Board and Founder, and Robert Pender, our Executive Co-Chairman, Executive Co-Chairman of the Board and Founder.

•We and our contractors, including our EPC contractors, may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us.

•We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs.

•We may not construct or operate all of our proposed LNG facilities or pipelines or any additional LNG facilities or pipelines beyond those currently planned, and we may not pursue some or any of the bolt-on expansion opportunities we have identified at our current projects, which could limit our growth prospects.

•We are dependent on our contractors for the successful completion of our projects and any bolt-on expansion opportunities at our projects that we may pursue, and any failure by our contractors to perform their contractual obligations could have a material adverse impact on our projects.

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•We have not entered into all of the definitive agreements for our future projects and expansions, and there can be no assurance that we will be able to do so on a timely basis or on terms that are acceptable to us.

•Certain of our contractual arrangements relating to development and construction of our projects include termination rights that, if exercised, could have a material adverse impact on our projects.

•Our estimated costs for our projects have been, and continue to be, subject to change due to various factors.

•Delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

•Our business could be materially and adversely affected if we do not secure the right or if we lose the right to situate certain lateral pipelines, longer-haul pipelines or any other pipeline infrastructure for any of our projects on property owned by third parties, or if we do not complete the construction of those pipelines in a timely fashion.

•The natural gas liquefaction system and mid-scale design we utilize at our projects are the first of such sized modules developed by us and Baker Hughes, and there can be no assurance that these modules, or our projects, will achieve the level of performance or other benefits that we anticipate over the long term.

•Competition in the LNG industry is intense, and certain of our competitors may have greater financial, engineering, marketing and other resources than we have.

•We face competition based upon the international market price for LNG.

•Servicing our indebtedness and preferred equity will require a significant amount of cash and we may not have sufficient cash, operating cash flows and capital resources to service our existing and future indebtedness and preferred equity.

•We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

•If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.

•VG Partners has significant influence over us, including control over decisions that require their approval, which could limit your ability to influence the outcome of key transactions, including a change of control.

•There is the possibility of significant fluctuations in the price of our Class A common stock.

•We cannot guarantee that we will pay further dividends on our Class A common stock in the future and, consequently, your ability to achieve a return on your investment will depend on appreciation in the price of our Class A common stock.

•We face risks related to the uncertainty regarding the future of international trade agreements and the United States’ position on international trade.

The summary risk factors described above should be read together with our risk factors as described in the section titled Risk Factors in Part I, Item 1A. and the other information set forth on this Form 10-K. The risks summarized above or described in full below are not the only risks that we face. Additional risks and uncertainties not precisely known to us, or that we currently deem to be immaterial, may also materially adversely affect our business, financial condition, results of operations and future growth prospects.

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PART I

ITEM 1. BUSINESS

Overview

Our Company

Venture Global is a long-term, low-cost provider of U.S. LNG sourced from resource rich North American natural gas basins. Our integrated assets span the LNG supply chain, including LNG production, natural gas transportation, shipping and regasification. Our innovative approach, which is both scalable and repeatable, allows us to bring low-cost LNG to a global market years faster than traditional LNG projects. We believe supplying this clean, affordable fuel promotes global energy security and diversification and is essential to meeting growing global energy demand.

Natural gas is a vital global resource that underpins economic development through the generation of reliable electricity. By cooling natural gas to -260°F, it is converted to LNG—reducing its volume to 1/600th of its original state for efficient transport by LNG tankers to international markets lacking domestic supply, displacing more carbon intensive sources of energy such as coal and oil. Venture Global’s modular, “design‑one, build‑many” approach enables faster, more cost-efficient construction and the rapid deployment of productive assets compared with traditional LNG projects, forming the foundation of both our operating platform and development strategy.

Liquefaction and Export Projects

We are operating, constructing, and developing multiple LNG export projects in Louisiana. Each project is designed to include an LNG facility and associated pipeline systems to deliver natural gas into the LNG facility through interconnected interstate and intrastate pipelines. We currently own all or a majority interest in each of our LNG projects providing full managerial control and operational flexibility.

Our “design‑one, build‑many” approach allows us to pursue bolt-on expansions efficiently across existing sites. These bolt-on expansion projects are designed to leverage existing plant infrastructure and equipment to reduce per tonne capital costs relative to new, or greenfield, developments, although they may require, among other things, incremental natural gas supply arrangements, pipelines, and pipeline transportation capacity for the applicable project in order to support the additional capacity of such bolt-on expansions.

The "expected" annualized production capacity for each facility represents anticipated sustainable post-COD production levels under normal operating conditions (e.g., typical day-to-day temperatures, pressure, humidity, reliability, gas supply and standard operating parameters). Our facilities may temporarily achieve higher throughput—i.e., the maximum technical output—under optimal or "peak" conditions (e.g., cooler ambient temperatures, peak equipment efficiency, ideal feed-gas composition and minimal downtime). Actual performance will vary over time and depends on a multitude of factors. The "currently permitted" capacity reflects the volumes authorized to date by

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one or more relevant regulatory agencies. In certain cases, these amounts represent the lower end of our fully permitted range—such as where FERC authorization has been granted but DOE approval for exports to Non-FTA Nations remains pending. Accordingly, currently permitted capacities may increase as additional authorizations are received.

The following table summarizes our current LNG export projects, together with their stages of advancement and permitted capacities.


Project Name	Liquefaction Trains	Annualized Production Capacity (mtpa)			Stage of Development
		Expected	Expected Peak	Currently Permitted
Calcasieu Project	18	11.2	12.4	12.4	Operating
Plaquemines Project	36	28.0	35.0	24.0(1)	Construction and Commissioning
Plaquemines Expansion Project	32	25.8(2)	31.0(2)	—(3)	Development
CP2 Project	36	29.0	35.0	28.0(4)	Construction
CP2 Expansion Project	12	9.7(2)	11.7(2)	—(5)	Development
CP3 Project	60	48.3(2)	58.3(2)	—(6)	Development
Total	194	152.0	183.4	64.4

____________

(1) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the Plaquemines Project from 27.2 mtpa to 35.0 mtpa. We have a pending application with DOE to increase the authorized exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa, and we intend to submit another DOE export application in the first half of 2026 to increase the authorized export volumes to 35.0 mtpa. See —Governmental Regulation of this Item 1.

(2) Anticipated based on capacity, scale, location and infrastructure, and expected to be completed in phases. Subject to regulatory review and approval, among other things, and is subject to change based on a variety of factors. See —Governmental Regulation of this Item 1 and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

(3) In November 2025, we filed applications with the FERC and DOE proposing a 31.0 mtpa expansion of the Plaquemines Project (the “Plaquemines Expansion Project”). The Plaquemines Expansion Project replaces the Delta Project which we withdrew from the FERC pre-filing process on June 10, 2025, as described in —Governmental Regulation of this Item 1.

(4) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the CP2 Project to 35.0 mtpa. In February 2026, we submitted an application with the DOE to increase our authorized export volumes to FTA and non-FTA nations 35.0 mtpa. Both the FERC and DOE Non-FTA Nations authorizations are subject to on-going appeals. See —Governmental Regulation of this Item 1.

(5) We intend to file applications with the FERC and DOE proposing a 11.7 mtpa expansion of the CP2 Project (the "CP2 Expansion Project") in the first half of 2026. See —Governmental Regulation of this Item 1.

(6) As of the date of this Form 10-K, no FERC and no DOE filings have been made and none of the necessary approvals for the CP3 Project have been obtained.

Our Operational Strategy

Our primary goal is to become one of the lowest-cost providers of LNG in the industry. Our operations emphasize:

•Use of a proven liquefaction system with a standardized configuration across all facilities;

•Leveraging scale and standardization across our projects to optimize performance and reduce redundancy;

•Data-driven production optimization and reliability initiatives;

•Vertical integration through shipping and regasification in key import markets;

•Long-term natural gas supply and transportation agreements with domestic producers; and

•Comprehensive health, safety and environmental programs.

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We believe our unique electric motor driven modular configuration and our owner-led construction model enable us to produce low‑cost, reliable LNG for customers while maintaining flexibility and speed in project execution.

LNG produced by our facilities is sold to our customers on either a FOB, DPU or DES basis, directly from our projects or through our sales and shipping business. In addition, we have secured LNG regasification capacity in certain key import markets to support customers and further differentiate our integrated offering from that of other North American LNG exporters.

Our Commercial Arrangements and Strategy

Our commercial strategy is intended to capture value across the full lifecycle of our LNG facilities—during testing and commissioning, operations under contracted sales agreements, and through the sale of excess production capacity. We employ a portfolio contracting approach designed to sell sufficient term liquefaction capacity to support financing while optimizing revenue and cash flow. This framework includes:

•Commissioning sales, representing LNG produced and sold, on a forward, spot or short-term contracted basis, during the testing and commissioning phase prior to COD;

•Contracted SPAs, generally consisting of long‑term agreements with third‑party customers that commence upon achievement of COD or a firm start date, and provide predictable revenue streams that have historically supported project financing; and

•Excess capacity sales, representing LNG produced above guaranteed nameplate capacity or Contracted SPA commitments and marketed under short‑, medium‑, or long‑term arrangements, providing commercial and pricing flexibility.

LNG produced by our facilities is sold to our customers directly from our projects or through our sales and shipping business on either a FOB, DPU or DES basis.

•The LNG sales price structure under our Contracted SPAs generally includes (i) a fixed liquefaction fee, a portion of which is subject to an annual adjustment for inflation; (ii) a variable commodity fee equal to at least 115% of Henry Hub per MMBtu of LNG; and (iii) a transportation charge, if sold on a DPU basis.

•The LNG sales price structure of our commissioning sales and excess capacity sales generally aligns with our Contracted SPAs for FOB delivery, whereas our DES agreements are structured with a single sales price that includes transportation and is indexed to foreign gas markets, such as TTF or JKM.

Taken together, we believe this contracting approach positions us to achieve a balanced revenue mix across long‑term contracted volumes and opportunistic spot or medium‑term sales.

Commissioning Sales

Our modular design allows a phased start-up of our LNG production facilities and the generation and sale of LNG prior to COD. Due to our unique modular development approach and configuration consisting of many mid-scale liquefaction trains, which are delivered and installed sequentially, it is necessary to commission and test our LNG facilities sequentially over a longer period of time than traditional LNG facilities with substantially fewer, larger-scale liquefaction trains. The commissioning of the liquefaction trains at our facilities begins while portions of our facilities remain under construction.

LNG produced during this phase is sold under master SPAs to customers as either single cargos or as strips of multiple cargos and are based on spot and/or forward prices, generally consisting of a liquefaction fee and a variable commodity fee, at the time of execution.

We expect to continue to generate proceeds from commissioning sales of LNG at each project until COD. The Calcasieu Project generated proceeds from commissioning sales of LNG beginning in the first quarter of 2022

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through COD in April 2025. Similarly, the Plaquemines Project began commissioning sales of LNG in January 2025, which are expected to continue through the respective CODs of its two phases.

Contracted SPAs

As of December 31, 2025, we have executed 47.0 mtpa of SPAs with a well-recognized group of third-party customers. Approximately 96% of contracted volumes are under 20-year, fixed price sales and purchase agreements that provide stable, long-term cash flows. Under these SPAs, customers pay a fixed liquefaction fee—even if cargo deliveries are suspended or canceled (i.e., "take or pay")—plus a variable commodity fee for volumes delivered. These Contracted SPAs have historically served as the commercial foundation for obtaining non‑recourse project level financing, demonstrating contracted revenue visibility and creditworthy counterparties.

•Post-COD SPAs — Our project companies for the Calcasieu, Plaquemines, and CP2 projects have executed post‑COD SPAs under which LNG is sold based on the pricing structure described above, commencing upon achievement of COD of the relevant project or phase thereof. COD is deemed achieved only once the relevant project company has notified the customer that the relevant project has been completed and commissioned, including any ramp up period, and is capable of delivering LNG that meets contractual quality and quantity standards.

•Firm-start SPAs — Our sales and shipping business—through VG Commodities—has executed long-term SPAs under which LNG is sold based on the pricing structure described above, commencing on set dates in 2029 and 2030. The LNG to be delivered under these agreements will be sourced by VG Commodities from the Calcasieu, Plaquemines or CP2 projects pursuant to VG Commodities' intercompany excess capacity SPAs. We expect the obligation to deliver under these contracts will transition to CP2 upon achievement of COD of the relevant phase of the CP2 Project.

Together, we believe that these Contracted SPAs, combined with our modular and capital‑efficient development model, support our ability to finance, construct, and bring projects online on an accelerated timeline when compared to traditional stick-built projects.

Excess Capacity Sales

Our facilities are designed to produce LNG in excess of their guaranteed nameplate capacity—by as much as 40% annually—reflecting the annualized expected production capacity under normal ambient weather conditions. The performance of liquefaction trains during commissioning at the Plaquemines Project supports these production capacity expectations. In addition, our recent filings with the FERC contemplate expected annualized peak production capacity performance in excess of this 40% figure at the Plaquemines Project. This excess capacity creates the potential for additional cash proceeds from our projects.

Post-COD, any LNG produced in excess of nameplate capacity from the Calcasieu, Plaquemines, and CP2 projects is intended to be sold to VG Commodities under intercompany excess capacity SPAs. LNG sold under such intercompany excess capacity SPAs can, to the extent not previously committed to third parties, be resold to third-party customers at our discretion under contracts of various tenors, providing flexibility to manage pricing exposure and optimize portfolio returns. We expect to enter into similar intercompany excess capacity SPAs for our other development projects. VG Commodities has contracted to resell a portion of the excess capacity from the Calcasieu Project to a third-party pursuant to a long-term SPA.

Our Project Development and Construction Strategy

Our project design utilizes proven liquefaction system technology and equipment in a unique mid-scale, factory-fabricated configuration developed by Venture Global. Rather than utilizing two or three large, complex liquefaction trains, our facilities utilize multiple electric motor driven mid‑scale trains that are prefabricated in Italy and shipped to the project site fully assembled and packaged for installation, allowing on‑site work to progress in parallel with fabrication.

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We believe our innovative configuration, long-term equipment contracting strategy, and internal owner-led engineering, procurement and construction management ("EPCM") approach significantly reduce project costs, construction time and schedule risk as compared to traditional LNG projects. This combination enables greater cost competitiveness while supporting the early production of commissioning cargos. For example, both the Calcasieu and Plaquemines projects began LNG production approximately two and a half years after their respective final investment decisions, while significant construction work was still underway. The CP2 Project is currently targeting similar or improved execution timelines.

By leveraging standardized factory-fabricated equipment and our “design one, build many” methodology, we aim to continuously apply lessons learned from earlier projects to subsequent developments—enhancing execution efficiency, reducing costs, accelerating delivery, and expanding capacity.

Bolt-on Expansion Opportunities

Our projects are sited and designed to enable optimization, additional capacity and bolt‑on expansions. Each facility incorporates laydown areas, shared infrastructure redundancies and standardized liquefaction modules designed for scalable build-out. This design provides flexibility in phasing and scope of future bolt-on expansions, allowing us to respond efficiently to market demand while leveraging existing infrastructure.

Any incremental equipment is expected to utilize certain pre‑existing plant facilities and infrastructure, such as marine offloading facilities, LNG storage tanks, and perimeter walls. Bolt-on expansion projects may require incremental natural gas supply arrangements, new or expanded pipelines (which can be developed in phases), and associated transportation capacity to support additional throughput.

Testing and Commissioning Process

Due to our unique design using numerous mid-scale liquefaction trains, which are delivered and installed sequentially, it is necessary to commission and test our LNG facilities over a longer period of time than traditional LNG facilities. The operation and commissioning of the liquefaction trains at our facilities begins while portions of our facilities remain under construction, serially bringing modules and production capacity online for commissioning. This important reliability and technical requirement results in earlier production of LNG than with traditional LNG facilities.

Our Complementary Infrastructure

Pipeline Projects

We are in varying stages of construction and development of pipelines to establish complementary gas transportation for our LNG projects. For example, we partnered with WhiteWater Midstream, LLC, a Texas-based pipeline developer and operator, to jointly develop the approximately 190-mile Blackfin Pipeline project, a 48-inch intrastate pipeline designed to transport Permian and Eagle Ford-sourced gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline. In addition to the Blackfin Pipeline, we are developing several other pipelines intended to support production capacity for Phase 2 of the CP2 Project and our bolt-on expansion projects.

Shipping

To further vertically integrate our business and expand access to premium markets that have no or limited LNG transportation options, we are building a fleet of LNG tankers. We have contracted to acquire nine LNG tankers, seven of which have been delivered. The remaining LNG tankers are under construction and scheduled for delivery in 2026. In addition, we have chartered two LNG tankers to supplement delivery capacity until our full fleet is available.

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LNG Regasification Capacity

We have secured LNG regasification capacity in the United Kingdom and Greece, which is expected to allow us to supply LNG and regasified natural gas directly into the European market to current and additional downstream customers.

Carbon Capture and Sequestration Initiative

We plan to deploy carbon capture and sequestration systems adjacent to our Louisiana projects to reduce CO₂ emissions by compressing CO2 emissions from our projects and injecting them into subsurface saline aquifers near our project site. In July 2023, we submitted an application to the U.S. EPA for a Class VI well permit in respect of the Calcasieu Project and CP2 Project. We are in the process of completing the remaining applications for regulatory approval in respect of our current projects. We have also secured the requisite pore space leases with the State of Louisiana.

Our Liquefaction Projects

Calcasieu Project



Calcasieu Project




Project design:

Expected annualized production capacity			11.2 mtpa(1)
Expected annualized peak production capacity			12.4 mtpa
Potential bolt-on expansion incremental capacity			Up to 4.5 mtpa(2)
Liquefaction system			18 liquefaction trains
LNG storage			2 × 200,000 cubic meter cryogenic LNG storage tanks
Power supply			1 power island system (620 MW nominal / 720 MW peak capacity consisting of 5 gas turbine generators and 2 steam turbine generators)
Gas pre‑treatment system			3 units
Berths			2 berths
Pipeline			TransCameron Pipeline: 24-mile interstate pipeline

Key permits:
FERC approval; DOE approval – FTA & Non-FTA Nations			12.4 mtpa

____________

(1) Nameplate capacity of 10.0 mtpa.

(2) Potential bolt-on expansion opportunity based on facility capacity, scale, location and infrastructure. Subject to regulatory approval, among other things, and may change based on design considerations, regulatory review process, contractor engagement and other factors.

Project Construction, Commissioning and Completion

Construction of the Calcasieu Project is complete, and the facility achieved COD on April 15, 2025. COD followed completion of commissioning and testing to confirm the ability to safely and reliably produce LNG at designed nameplate levels. During commissioning, additional remediation work was performed on the power island system’s heat‑recovery steam generators after the manufacturer’s fabrication change led to leakage issues. In addition, the gas pre‑treatment units required performance rectification before achieving Lender Reliability Performance Test completion and COD declaration.

As of December 31, 2025, the Calcasieu Project executed approximately 28.1 million work hours with a TRIR of 0.12, significantly outperforming the U.S. industry average of 2.2 for 2024.

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Commercial Arrangements

Upon achievement of COD, the Calcasieu Project commenced deliveries under its post-COD SPAs and intercompany excess capacity SPA with VG Commodities. The following table summarizes the Calcasieu Project's post-COD sales portfolio, up to our expected annualized production capacity volumes as of December 31, 2025.

mtpa

Delivery Terms

Tenor

Contracted, post-COD SPAs—Long-term(1)

8.5

FOB

20 years

Contracted, post-COD SPAs—Medium-term

1.5

FOB

3 to 5 years

Excess capacity sales under intercompany SPA with VG Commodities(2)

Up to 1.2

FOB

20 years

Total expected capacity post-COD under contract

11.2

____________

(1) Consists of six contracts, primarily with investment‑grade offtakers.

(2) Represents 1.2 mtpa of expected annualized production capacity in excess of the 10.0 mtpa nameplate capacity of the facility. Actual annual sales volumes may differ depending on operating conditions and maintenance schedules.  Any LNG produced in excess of nameplate capacity is sold under an intercompany excess capacity SPA between VGCP and VG Commodities. 

Plaquemines Project



Plaquemines Project	Phase 1	Phase 2




Project design:

Expected annualized production capacity	28.0 mtpa(1)
Expected annualized peak production capacity	35.0 mtpa

Liquefaction system	24 liquefaction trains	12 liquefaction trains
LNG storage	2 × 200,000 cubic meter cryogenic LNG storage tanks	2 × 200,000 cubic meter cryogenic LNG storage tanks
Power supply	2 power island systems (each with 620 MW nominal / 720 MW peak capacity consisting of 5 gas turbine generators and 2 steam turbine generators)
Gas pre‑treatment system	4 units	2 units
Berths	2 berths	1 berth
Pipeline	Gator Express Pipeline: one 15-mile interstate pipeline & one 12-mile interstate pipeline

Key permits:
FERC approval	27.2 mtpa(2)
DOE approval – FTA Nations	27.2 mtpa(2)
DOE Non‑FTA Nations	24.0 mtpa(2)
Anticipated project timeline:


Targeted COD	Q4 2026	Mid-2027

____________

(1) Nameplate capacity of 20.0 mtpa.

(2) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the Plaquemines Project from 27.2 mtpa to 35.0 mtpa. We have a pending application with DOE to increase the authorized exports to Non-FTA Nations from 24.0 mtpa to 27.2 mtpa, and we intend to submit another DOE export application in the first half of 2026 to increase the authorized export volumes to 35.0 mtpa. See —Governmental Regulation of this Item 1.

Project Construction and Commissioning

The Plaquemines Project is being constructed pursuant to two EPC contracts, one per phase, or the Plaquemines EPC Contracts, entered into with KZJV. Under the Plaquemines EPC Contracts, VGPL is responsible

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for executing or directly managing significant scopes of work. Baker Hughes, UOP and CB&I are each providing and constructing the mid-scale, factory-built liquefaction trains and power island systems, the pre-treatment system, and storage tanks, respectively.

As of December 31, 2025, all 36 liquefaction trains were operating and capable of producing LNG, while still undergoing testing and commissioning. In addition, the final portion of the Gator Express Pipeline was placed in service by FERC in December 2024. While construction remains ongoing, portions of the facility are undergoing commissioning activities. Our gradual commissioning process starts with addressing identified operational deficiencies, testing individual components and eventually extends to encompass testing and tuning our entire fully-integrated facilities. For example, one issue that has arisen relates to substantial delays in the operation of our combined cycle power island system. To mitigate such delays, we have permitted and incorporated 400 MW of temporary power at the Plaquemines facility. This allows us to progress commissioning efforts, including the production and sale of commissioning cargos, while we complete the construction of our combined cycle power plants. Despite these challenges, the Plaquemines Project has exported a significant number of commissioning cargos while construction, rectification, and reliability adjustments continue.

We currently estimate that approximately $0.6 billion to $1.0 billion of the Total Project Cost for the Plaquemines Project has yet to be paid as of December 31, 2025. Our estimated Total Project Cost is based upon our experience to date and reflects the current inflationary, macroeconomic, and regulatory environment. However, the costs to complete the Plaquemines Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors. See Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors of this Form 10-K.

As of December 31, 2025, the Plaquemines Project had executed approximately 90.6 million work hours with a TRIR of 0.18, significantly outperforming the U.S. industry average of 2.2 for 2024.

Commercial Arrangements

As facility testing and commissioning continue, the Plaquemines Project has exported commissioning cargos to various customers consistent with our commissioning sales strategy.

Upon achievement of COD for the respective phases of the project, the Plaquemines Project will begin deliveries under its post-COD SPAs and intercompany excess capacity SPA with VG Commodities. The following table summarizes the Plaquemines Project's post-COD sales portfolio, up to our expected annualized production capacity volumes as of December 31, 2025:

mtpa

Delivery Terms

Tenor

Phase 1

Contracted, post-COD SPAs—Long-term(1)

13.0

FOB, DPU

20 years

Contracted, post-COD SPAs—Medium-term

0.3

FOB

3 years

Phase 2

Contracted, post-COD SPAs—Long-term(1)

6.7

FOB

20 years

Excess capacity sales under intercompany SPAs with VG Commodities(2)

Up to 8.0

FOB

20 years

Total expected capacity post-COD under contract

____________

(1) Includes five and seven contracts for Phases 1 and 2, respectively, primarily with investment‑grade offtakers.

(2) Represents 8.0 mtpa of expected annualized production capacity in excess of the 20.0 mtpa (Phase 1 – 13.3 mtpa; Phase 2 – 6.7 mtpa) nameplate capacity of the facility. Additional approvals from FERC and DOE are required to produce and export at this level of expected annualized production capacity. See —Governmental Regulation of this Item 1. Actual annual sales volumes may differ depending on operating conditions and maintenance schedules.  Any LNG produced in excess of nameplate capacity is sold under the respective intercompany excess capacity SPA between VGPL and VG Commodities. 

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Plaquemines Expansion Project



Plaquemines Expansion Project			All phases




Anticipated project design(1):

Expected annualized production capacity			25.8 mtpa(2)
Expected annualized peak production capacity			31.0 mtpa(3)

Liquefaction system			32 liquefaction trains
Power supply			2 power island systems (each with 620 MW nominal / 720 MW peak capacity consisting of 5 gas turbine generators and 2 steam turbine generators)
Gas pre‑treatment system			5 units
Berths			1 berth
Pipeline			Cloud Connector Pipeline: 340-mile intrastate pipeline

____________

(1) Anticipated based on capacity, scale, location and infrastructure, and expected to be completed in phases. Subject to regulatory review and approval, among other things, and is subject to change based on a variety of factors. See —Governmental Regulation of this Item 1 and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

(2) Nameplate capacity of 17.8 mtpa.

Project Development

The Plaquemines bolt-on expansion project (the "Plaquemines Expansion Project") represents an evolution of our development strategy in Plaquemines Parish, LA and supersedes the previously contemplated Delta Project. In November 2025, we filed an application with the FERC proposing a 31.0 mtpa expansion of the existing Plaquemines Project LNG facilities in lieu of further pursuing the Delta Project, which represented a higher cost and longer duration development opportunity. Accordingly, the Delta Project was withdrawn from FERC pre-filing in June 2025, as described in —Governmental Regulation of this Item 1.

The Plaquemines Expansion Project is planned to be interconnected with the existing Plaquemines LNG terminal and is expected to share certain existing facilities, including LNG storage tanks, LNG loading berths, and marine facilities. Further, the project is expected to incorporate additional liquefaction trains and associated equipment within a site immediately adjacent to the existing Plaquemines Project site. We expect to develop, finance and construct the Plaquemines Expansion Project in phases, focusing first on the installation of liquefaction trains that can quickly be added to the existing infrastructure with limited expansion of ancillary equipment.

The Plaquemines Expansion Project will not include any new FERC-jurisdictional interstate pipeline facilities; rather, feed gas for the project will be delivered through a non-jurisdictional intrastate pipeline system that has yet to be constructed, connecting the project to the existing natural gas pipeline network in northern Louisiana.

As of December 31, 2025, we have completed significant engineering studies and simulations, including certain marine berth simulations, in support of the project. We expect to begin construction of the Plaquemines Expansion Project upon receipt of all required regulatory approvals and are targeting the start of construction by the second half of 2027, subject to regulatory approvals and the execution of sufficient SPAs to support project financing.

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CP2 Project



CP2 Project	Phase 1	Phase 2




Anticipated project design:

Expected annualized production capacity	29.0 mtpa((1)
Expected annualized peak production capacity	35.0 mtpa

Liquefaction system	26 liquefaction trains	10 liquefaction trains
LNG storage	2 × 200,000 cubic meter cryogenic LNG storage tanks	2 × 200,000 cubic meter cryogenic LNG storage tanks
Power supply	2 power island systems (each with 620 MW nominal / 720 MW peak capacity consisting of 5 gas turbine generators and 2 steam turbine generators)
Gas pre‑treatment system	4 units	2 units
Berths	2 berths
Pipelines	CP Express Pipeline: one 85-mile interstate pipeline Blackfin Pipeline: one 35-mile intrastate pipeline and one 158-mile intrastate pipeline

Key permits:
FERC approval	28.0 mtpa(2)
DOE approval – FTA Nations	28.0 mtpa(2)
DOE Non‑FTA Nations	28.0 mtpa(2)
Anticipated project timeline:
Final investment decision / financial closing	July 28, 2025	Mid-2026
Targeted COD	Late-2029	Mid-2030

____________

(1) Nameplate capacity of 20.0 mtpa (14.4 mtpa and 5.6 mtpa for Phases 1 and 2 of the CP2 Project, respectively).

(2) In December 2025, we filed an application with the FERC to increase the permitted production capacity of the CP2 Project to 35.0 mtpa. In February 2026, we submitted an application with the DOE to increase our authorized export volumes to FTA and non-FTA nations 35.0 mtpa. Both the FERC and DOE Non-FTA Nations authorizations are subject to on-going appeals. See —Governmental Regulation of this Item 1. See —Governmental Regulation of this Item 1.

Project Engineering, Procurement, and Construction

In 2025, we commenced site work on Phase 1 of the CP2 LNG facility and the CP Express Pipeline following receipt of final approval and notices to proceed with on-site construction from the FERC. In July 2025, Phase 1 of the CP2 Project achieved FID and obtained project financing to fund the development and construction of Phase 1 of the CP2 Project. In October 2025, CP2 received the final authorization from the DOE to export LNG to Non-FTA Nations. We have completed substantial engineering, procurement, manufacturing, and off-site construction work for Phase 2 of the CP2 Project in advance of a final investment decision, the timing of which remains subject to certain market and other conditions. See —Governmental Regulation and Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K.

In addition to the CP Express Pipeline, we have partnered with WhiteWater Midstream, LLC to jointly develop the Blackfin Pipeline. The Blackfin Pipeline is an intrastate pipeline designed to facilitate the transportation of Permian and Eagle Ford Basin-sourced natural gas from the Matterhorn Express pipeline to certain interconnecting pipelines, including the CP Express Pipeline.

For the CP2 Project, we are managing and expect to continue to manage additional scopes of work beyond those managed in our previous two projects by directly taking on incremental oversight, contract management and coordination responsibilities, based on lessons learned and the relationships we have fostered with construction and fabrication subcontractors while developing the Calcasieu and Plaquemines projects. Additionally, we have added

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nitrogen rejection units in the CP2 design. This facilitates the use of Permian Basin-sourced high nitrogen content natural gas, which often trades at a substantial discount to Henry Hub index pricing, in the production of LNG at the CP2 Project.

We currently estimate that the Total Project Costs for the first and second phase of the CP2 Project will range between approximately $32.5 billion and $33.5 billion, including EPC contractor profit and contingency, owners’ costs and financing costs. The estimated Total Project Cost for the first and second phases of the CP2 Project has increased due to factors including design modifications to accommodate increased production levels and allow for potential future bolt-on expansions to the CP2 Project. Additional drivers include increased contingency reserves for the potential impact of tariffs in place as of December 31, 2025, but does not reflect potential incremental tariff exposure that may arise as a consequence of evolving tariff policies. Our estimated Total Project Cost is based upon our experience to date and reflects the current inflationary environment and current known tariff exposure. However, the costs to complete the CP2 Project have increased in the past, and may increase further in the future, potentially materially, compared to our current estimates as a result of many factors. See Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors of this Form 10-K.

As of December 31, 2025, the CP2 Project had executed approximately 13.2 million work hours with a TRIR of 0.18, significantly outperforming the U.S. industry average of 2.2 for 2024.

Commercial Arrangements

The CP2 Project has not yet commenced LNG production or commissioning activities. However, CP2 has executed post-COD SPAs with third-party customers and intercompany excess capacity SPA with VG Commodities. In addition, VG Commodities has entered into Firm-start SPAs with third-party customers providing for the delivery of LNG from the CP2 Project upon achievement of COD of phase 2 of the project or from Venture Global's portfolio at a fixed start date. We expect some of these SPAs will transition to the CP2 Project at that time.

Upon achievement of COD for the respective phases of the project, the CP2 Project will begin deliveries under its post-COD SPAs and intercompany excess capacity SPA with VG Commodities. The following table summarizes the CP2 Project's post-COD sales portfolio, up to our expected annualized production capacity volumes as of December 31, 2025:

MTPA

Delivery Terms

Tenor

Phase 1

Contracted, post-COD SPAs—Long-term(1)

13.5

FOB

20 years

Phase 2

Contracted, post-COD SPAs—Long-term(1)

1.0

FOB

20 years

Firm-start SPAs contracted under VG Commodities(2)

2.5

FOB

20 years

Excess capacity sales under intercompany SPAs with VG Commodities(3)

Up to 9.0

FOB

20 years

Total expected capacity post-COD under contract

26.0

____________

(1) Includes ten contracts, primarily with investment‑grade offtakers.

(2) Represents Firm-start SPAs with VG Commodities which is expected to transition to CP2 upon COD of Phase 2 of the project. See – Our Sales and Shipping Business of this Item 1.

(3) Represents 9.0 mtpa of expected annualized production capacity in excess of the 20.0 mtpa (Phase 1 – 14.4 mtpa; Phase 2 – 5.6 mtpa) nameplate capacity of the facility. Additional approvals from FERC and DOE are required to produce and export at this level of expected annualized production capacity. See —Governmental Regulation of this Item 1. Actual annual sales volumes may differ depending on operating conditions and maintenance schedules. Any LNG produced in excess of nameplate capacity is sold under an intercompany excess capacity SPA between Calcasieu Pass and VG Commodities. 

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As of December 31, 2025, the CP2 Project had 3.0 mtpa of nameplate capacity that had not yet been contractually committed under post-COD SPAs. In February 2026, the CP2 Project executed a 20-year post-COD SPA for the delivery of 1.5 mtpa from Phase 2 of the CP2 Project, increasing the total expected capacity post-COD under contract from 26.0 mtpa to 27.5 mtpa. After achieving COD, we intend to market and sell any quantities of LNG that are not contractually committed through VG Commodities.

CP2 Expansion Project



CP2 Expansion Project			All phases




Anticipated project design(1):


Expected annualized production capacity			9.7 mtpa(2)(3)
Expected annualized peak production capacity			11.7 mtpa
Liquefaction system			12 liquefaction trains
Power supply			1 power island systems (each with 620 MW nominal / 720 MW peak capacity consisting of 5 gas turbine generators and 2 steam turbine generators)
Gas pre‑treatment system			3 units
Berths			1 berth
Pipeline			Marais Pipeline: one 45-mile intrastate pipeline and one 40-mile intrastate pipeline

____________

(2) Nameplate capacity of 6.6 mtpa.

(3) We intend to file applications with the FERC and DOE proposing a 11.7 mtpa expansion of the CP2 Project (the "CP2 Expansion Project") in the first half of 2026. See —Governmental Regulation of this Item 1.

Project Development

The CP2 bolt-on expansion project (the "CP2 Expansion Project") is expected to incorporate additional liquefaction trains, equipment, and a new FERC-jurisdictional interstate pipeline facility with existing equipment and infrastructure from the CP2 Project. The majority of the expansion facilities will be constructed within the existing industrial footprint and inside the perimeter wall that encloses the current CP2 Project site, minimizing additional requirements and infrastructure modifications. We expect to develop, finance and construct the CP2 Expansion Project in phases, focusing first on the installation of liquefaction trains that can quickly be added to the existing infrastructure with limited expansion of ancillary equipment. We believe this phased development of the bolt-on expansion, once implemented, will demonstrate our ability to quickly deploy incremental capacity within an established footprint in a cost-efficient manner.

As of December 31, 2025, we have completed significant engineering studies and simulations, including certain marine berth simulations, in support of the project. We expect to begin construction of the CP2 Expansion Project upon receipt of all required regulatory approvals and are targeting the start of construction by the first half of 2027, subject to the execution of sufficient SPAs to support project financing.

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CP3 Project



CP3 Project	Phase 1	Phase 2




Anticipated project design(1):

Expected annualized production capacity	48.3 mtpa(2)
Expected annualized peak production capacity	58.3 mtpa

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(2) Nameplate capacity of 33.3 mtpa.

Project Development

Although we completed our initial consultation with FERC in December 2024, as of December 31, 2025, we had not initiated the pre-filing process for the CP3 Project with FERC or entered into definitive agreements necessary for the project’s development and construction. While preliminary engineering and feasibility work, including certain marine berth simulations, have been conducted in support of early-stage development, overall project advancement remains in its initial development stage as we continue to evaluate market conditions and sequencing across our project portfolio. We expect that the construction, commissioning and operational start-up of the liquefaction plant will be substantially similar to our other projects, but we intend to prioritize our lower-cost bolt-on expansion opportunities ahead of the CP3 Project.

Our Sales and Shipping Business

Our sales and shipping business, which includes the activities of our wholly owned entity, VG Commodities, serves as the Company's commercial arm for the sale of LNG volumes acquired from the Company's LNG projects in excess of that currently contracted directly by the projects, and manages shipping to optimize portfolio value and flexibility. VG Commodities engages in both third-party sales and intercompany purchase arrangements, on a short-, medium- and long-term basis, enabling the efficient commercial marketing and contracting of LNG production across Venture Global's projects.

Commercial Arrangements

VG Commodities has entered intercompany excess capacity SPAs with the Calcasieu, Plaquemines and CP2 projects to acquire LNG produced in excess of each project's nameplate capacity. This provides VG Commodities access to up to 18.2 mtpa of incremental LNG subject to operating conditions, maintenance schedules and other factors affecting production, and permitting. One half of the excess LNG VG Commodities acquires from the Calcasieu Project is committed for sale under a 20-year FOB SPA with a third-party at prices indexed to international market gas rates. The remainder of VG Commodities' excess volumes may be resold to other third party customers under contracts of varying tenors, providing pricing flexibility and portfolio optimization opportunities. We expect to enter into similar intercompany excess capacity SPAs for our other development projects.

VG Commodities has also executed Firm-start SPAs with third-party customers to sell a total of 2.5 mtpa of LNG, generally on a long-term basis, commencing between 2029 and 2030. These agreements provide fixed start dates for the sale of LNG sourced from the CP2 Project or, prior to COD of the respective phases of the project, from excess capacity sourced from the Calcasieu, Plaquemines or CP2 projects. The pricing terms are consistent with the Company's other long-term post-COD SPAs, including both a fixed facility and a variable commodity fee. We expect the obligation to deliver under these contracts will transition to CP2 upon achievement of COD of the relevant phase of the CP2 Project.

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VG Commodities intends to maintain a balanced portfolio of long-term, medium-term and short-term sales to optimize pricing outcomes, manage risk and maximize returns across the Venture Global asset base.

Shipping and Logistics

VG Commodities manages the Company's shipping portfolio, including wholly owned and chartered LNG tankers, to support delivery commitments under its SPAs and provide flexibility in matching cargo destinations with market demand. This managed LNG delivery and logistics capability is the beneficiary of LNG regasification capacity the Company has secured at the Alexandroupolis LNG terminal in Greece and forthcoming regasification capacity under construction at the Grain LNG terminal in the United Kingdom. These long-term, contracted regasification positions support reliable import access for our managed LNG sales to important import access points to the European natural gas market and support Venture Global's broader vertical integration strategy to expand its market reach.

Natural Gas Supply and Transportation

We procure and transport natural gas required to produce LNG at our facilities under long-term supply and transportation commitments with domestic producers and midstream pipeline operators. Our current portfolio of feed-gas supply agreements supports the Calcasieu, Plaquemines and CP2 projects. We will continue to expand this portfolio to meet the needs of our ongoing and future developments.

Through lateral pipelines that we developed, each project is connected to multiple major interstate or intrastate pipelines, providing access to highly liquid supply from leading U.S. shale formations—including the Haynesville, Permian and Marcellus/Utica basins—through interconnections with systems such as ANR Pipeline, Texas Eastern Transmission, Sabine Pipe Line, Columbia Gulf and Tennessee Gas Pipeline. Our existing gas-transportation agreements generally have 10- to 20-year terms and include options for extension.

To enhance supply diversity and reliability, we are developing additional pipeline infrastructure independently and in coordination with experienced third-party operators. Current initiatives include the Blackfin, Marais and Cloud Connector pipelines, which are expected to serve future phases of the Plaquemines and CP2 projects and other future projects or bolt-in expansions. These projects will provide incremental delivery capacity from the Permian, Haynesville, Eagle Ford and mid-continent shale formations and ensure stable, cost-effective access to feed-gas supply for our LNG facilities.

Our EPCM Model Approach and EPC Contracts

Since our first project, we have applied a hands-on approach to project execution by contracting directly with EPC contractors and key equipment suppliers rather than relying on traditional lump-sum, turn-key structures common in the LNG industry. Our integrated, owner-driven model has been a core differentiator in our ability to deliver projects efficiently and cost effectively. Building on that foundation, we have now advanced to an owner led EPCM model in the construction of the CP2 Project. Under this approach, we manage procurement and construction activities directly rather than outsourcing such activities to a single EPC contractor, thereby enabling our greater control over project execution, scheduling and cost outcomes. The EPCM model allows us to: (i) capture synergies across multiple projects by applying consistent design standards and vendor relationships, (ii) maintain continuity of specialized expertise across phases and sites, (iii) leverage historic performance and financial data to enhance transparency, staffing levels, efficiency and accountability over subcontractor performance and material costs, and (iv) mitigate exposure to redundant EPC administrative and back office cost escalation. By retaining these capabilities internally, we strengthen operational resilience in a market constrained by skilled labor and increase our ability to execute projects on accelerated timelines at lower capital cost per unit of production.

We constructed the Calcasieu Project pursuant to an EPC contract and have entered into EPC contracts for both phases of the Plaquemines and CP2 projects. While these agreements require each contractor to integrate equipment and facilities and guarantee full operation of the LNG export facilities, the nature of those agreements

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reflects a significant shift in our execution model. For the CP2 Project, we have assumed a substantially larger portion of engineering, procurement, and construction management activities directly—expanding our EPCM model beyond the level deployed at the Plaquemines Project. For future developments, we plan to negotiate EPC contracts with similar terms while expanding our self-managed EPCM activities, consistent with the approach used for our CP2 Project execution.

Phases 1 and 2 of the Plaquemines Project are governed by EPC contracts with KZJV, structured as reimbursable arrangements with target prices and schedule-based incentives. For example, KZJV will be paid a reimbursable sum for its scope of work, where we will reimburse KZJV for all reimbursable costs incurred in connection with the relevant work (such as costs for materials, transportation and equipment), plus a margin to cover overhead costs and expenses as well as an agreed profit margin. However, all other costs will not be reimbursed and will be borne by KZJV. The estimated reimbursable sum represents the “target price” for each phase of the Plaquemines Project, which is reflected in our estimated Total Project Costs for the Plaquemines Project. The target price is subject to adjustment under certain limited conditions, including pursuant to change orders we could submit with respect to the scope of work to be performed by KZJV or changes to the project schedule. The CP2 EPC contracts with Worley follow similar terms adapted to project scope and timeline. All agreements include defined change-order procedures, milestone incentives and shared cost-savings mechanism that promote timely completion and performance compliance.

Under each such EPC contract that we have entered into for our projects, the EPC contractor has an obligation to deliver a facility capable of passing certain performance tests. Further, under each such contract, the EPC contractor warrants that (i) it will perform the work under the EPC contract in full compliance with such contract, (ii) the materials and the work will be designed, manufactured, engineered, constructed, completed, pre-commissioned, commissioned, tested and delivered in a workmanlike manner and in accordance with each respective EPC contract, our standards, all permits and approvals of government authorities, applicable codes and standards and all applicable laws, (iii) the work will conform to the specifications and descriptions in its EPC contract, will be new, complete, and of suitable grade for the intended function and use, will be free from defects in design, material and workmanship, and will meet the requirements set forth in its EPC contract, (iv) the materials will be composed and made of only proven technology, of a type in commercial operation at the effective date of its EPC contract, (v) if a serial defect (two or more of the same components experience a defect of an identical or nearly identical nature) occurs as to its work done under the EPC contract prior to the expiration of each respective warranty period, it will redesign, repair or replace any materials as necessary and extend each respective warranty period for that portion of the work that is redesigned, repaired or replaced for an additional 12 months, and (vi) during the warranty period, it will perform tests, inspections or other diagnostic services requested by us and correct any non-conforming work discovered.

Consistent with our EPCM approach, we coordinate project execution through a network of specialized contractors and suppliers rather than a single, turn-key provider. This decentralized framework allows us to allocate critical scopes among industry experts while maintaining direct control over integration and oversight across all facilities.

Baker Hughes Master Agreement

We maintain a master supply relationship with Baker Hughes under a long-term master agreement, (the "Baker Hughes Master Agreement"), that governs the supply of key liquefaction and power equipment for our LNG projects. The agreement secures equipment supply, pricing, and reserved manufacturing capacity sufficient to support our existing and future development projects, subject to our compliance with the agreement and timely execution of project specific purchase orders.

Purchase orders under this agreement establish the terms for equipment supply, delivery terms, testing and performance guarantees. Baker Hughes is obligated to meet specified performance, reliability, and LNG quality standards, and to remedy or compensate for any deficiencies through corrective work or liquidated damages. The agreement also provides for pre-negotiated forms of purchase orders and long-term service arrangements for

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maintenance and operational support—already exercised for the Calcasieu and Plaquemines projects—and includes performance-availability guarantees with related incentive and liquidated damage provisions.

We have executed the necessary purchase orders for our projects under construction—including the Plaquemines and CP2 projects—and the agreement provides remaining reserved manufacturing capacity that can accommodate future developments—including the Plaquemines Expansion and CP2 Expansion projects as well as the CP3 Project—subject to execution within the applicable timelines provided under the Baker Hughes Master Agreement.

Human Capital Resources

Our human capital is our most valuable asset, and we place a high premium on attracting, developing and retaining talented and high performing employees. As of December 31, 2025, we had over 2,000 full-time employees working on our EPCM, project development, project financing, corporate finance, legal, and LNG marketing teams. As we develop and construct our projects, we expect to create additional highly skilled engineering, construction, manufacturing, and operating full-time and contractor jobs in Louisiana, Texas, and Virginia. We offer our employees a wide array of company-paid benefits and performance incentives, which we believe are competitive relative to others in our industry. 117 of our international employees are represented by a labor union and subject to a collective bargaining agreement. This agreement is negotiated annually. We believe our relationship with our employees to be good.

Community Outreach

We are committed to creating lasting positive impacts in the communities where we operate. The construction and operation of our LNG facilities generate significant employment opportunities and contribute to regional and national economic growth through local hiring and broad participation by subcontractors and suppliers.

We prioritize hiring in-state and local workers and continually invest in workforce development through technical training and apprenticeship programs. For example, we partner with local colleges to provide residents near our project sites with industry certifications in fields such as electrical, welding and construction trades. In addition, our apprenticeship program offers hands-on technical training and clear pathways to full-time employment with Venture Global.

Beyond employment and training, we support the economic vitality of our host communities through ongoing contributions, local partnerships and property tax payments that provide substantial funding for parish infrastructure and public services. Through these activities, we aim to lead our industry in fostering sustainable community growth and opportunity.

Health and Safety

We are committed to providing a safe work environment across our businesses and strive towards best in class practices. We have built a dedicated Health, Safety, Security, and Environment, or HSSE, team that is accountable for the safe and responsible execution of our projects and reports to our Chief Operating Officer. At our project sites, our goal is to implement comprehensive safety programs that are appropriate for the hazards present at the various stages of construction and commissioning. This includes daily safety inspections, recurring safety trainings, and regular safety meetings. Our rigorous safety standards are continuously reviewed and updated to ensure they are fit for purpose within our workforce, and we aim to meet the highest possible benchmarks. We believe that a strong safety culture leads to better safety performance, better operational performance, and higher staff morale. Our aggregate 0.17 TRIR which, when compared to the industry average for 2024 of 2.2 according to the Bureau of Labor safety statistics, is among the best in our industry and stands as a testament to our commitments.

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Governmental Regulation

Our operations are subject to extensive federal, state, and local regulation. Applicable laws require us to consult with applicable federal and state agencies, obtain and maintain applicable permits and authorizations, and comply with various ongoing regulatory requirements. This regulatory burden increases the cost of constructing and operating our projects, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations. See Item 1A.—Risk Factors—Risk Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K for more information.

Federal Energy Regulatory Commission (FERC)

The siting, construction, and operation of our facilities are subject to FERC’s approval and ongoing regulation, as is the construction and operation of our natural gas pipelines.

Pursuant to the Natural Gas Act, or the NGA, any person proposing to site, construct, or operate facilities (including LNG terminals) to be used for the export of natural gas from the United States to a foreign country must obtain authorization from FERC. FERC exercises comprehensive regulation of interstate natural gas pipelines, including requiring a certificate of public convenience and necessity to construct and operate such a pipeline, and requiring that the rates and terms of service for pipeline transportation service be just and reasonable under the NGA.

In addition to the initial FERC process for each of our projects summarized below, we note that throughout the life of each project, our LNG and pipeline facilities will be subject to ongoing FERC regulation and reporting requirements (as well as those of various other federal, state and local regulatory agencies). FERC’s jurisdiction under the NGA and NGPA allows it to impose civil and criminal penalties for any violations of the NGA or NGPA, and any rules, regulations or orders of FERC up to approximately $1.58 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

Calcasieu Project

FERC authorized the Calcasieu Pass LNG facility and the TransCameron pipeline in February 2019. The pipeline was placed in service by FERC in April 2021, and the terminal achieved full-in service status with FERC authorization in April 2025 after completion of an extended commissioning process. In June 2025, FERC approved a subsequent amendment of its authorizations increasing permitted peak production capacity from 12.0 to 12.4 mtpa.

Plaquemines Project

FERC authorized Phase 1 and 2 of the Plaquemines LNG facility and Gator Express pipeline in September 2019. Both pipeline laterals were placed in service by FERC during 2024, and commissioning of terminal facilities is ongoing under FERC supervision. In February 2025, FERC approved an increase in authorized capacity to 27.2 mtpa and in October 2025, granted an extension of time to complete construction and achieve full in-service status by December 2027. An additional application to increase permitted peak production capacity to 35.0 mtpa was filed in December 2025 and remains pending.

Plaquemines Expansion Project

In November 2025, Venture Global Plaquemines LNG, LLC and Plaquemines Expansion, LLC filed a joint application with FERC for authorization to construct and operate the Plaquemines Expansion Project adjacent to the Plaquemines Project. The proposed facilities include 32 new liquefaction trains capable of up to 31.0 mtpa of additional peak liquefaction capacity. This application is currently under FERC review.

CP2 Project

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FERC authorized the CP2 LNG facility and the CP Express pipeline in June 2024. Following a supplemental environmental review initiated in an order on rehearing, FERC reaffirmed the authorization in May 2025, and on-site construction began in June 2025. Construction and subsequent commissioning of the CP2 LNG facility, as well as the construction of CP Express pipeline, are subject to ongoing oversight and needed approvals from FERC. An appeal of FERC's orders remains pending before the U.S. Court of Appeals for the D.C. Circuit. In December 2025, we filed an application to amend the authorization to increase permitted peak production capacity from 28.0 to 35.0 mtpa.

CP2 Expansion Project

No application has been filed with FERC for the CP2 Expansion Project. Timing of any submission and approval depends on market conditions and regulatory priorities.

CP3 Project and Delta Project

No application application has been filed with FERC for the CP3 Project. Timing of any submission and approval depends on market condition and regulatory priorities. The previously proposed Delta Project was withdrawn from FERC's pre-filing process in June 2025 following the announcement of the Plaquemines Expansion Project noted above.

DOE Export Authorizations

Section 3 of the NGA requires any person seeking to import natural gas from, or export natural gas to, a foreign country to obtain authorization from the DOE. The DOE’s Hydrocarbons and Geothermal Energy Office, or HGEO (formerly named the Fossil Energy and Carbon Management Office), reviews applications to import or export natural gas.

The NGA sets forth separate standards of review for exports to (i) countries with which the United States has a free trade agreement requiring national treatment for trade in natural gas, or FTA Nations, and (ii) countries with which there is no such free trade agreement in effect, or Non-FTA Nations. Applications seeking authorization to export LNG to FTA Nations are deemed consistent with the public interest and must be granted without modification or delay. FTA Nations currently include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea, and Singapore. In contrast, Non-FTA Nations export applications are subject to a public interest review. HGEO will grant the requested authorization unless it finds, after providing for a public comment period, that the proposed exports will be inconsistent with the public interest, and may approve an application in whole or in part, and with such modifications and upon such terms and conditions as it deems necessary or appropriate. HGEO’s historical practice has been to act on long-term authorizations to export to Non-FTA Nations only after the FERC has authorized the siting, construction and operation of the associated LNG facilities.

On December 17, 2024, DOE publicly released a multi-volume study of its views of the potential effects of U.S. LNG exports on the domestic economy; U.S. households and consumers; communities that live near locations where natural gas is produced or exported; domestic and international energy security, including effects of U.S. trading partners; and the environment and climate—the 2024 LNG Export Study. DOE stated that it would use this study to inform its public interest review of and future decisions regarding exports to Non-FTA Nations. The period for public comment on the study expired on March 20, 2025.

On May 19, 2025, DOE issued its response to public comments on the 2024 LNG Export Study, concluding with detailed supporting analysis that LNG exports are consistent with public interest. Since that date, DOE has issued a series of orders authorizing US LNG exports, including certain orders for Venture Global projects addressed below. Nevertheless, there can be no assurance as to DOE’s future policies, or the impact of those policies on our existing and future projects, including the applications described below, or on any contracts related to our existing and future projects. For more information on these risks, see Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects of this Form 10-K.

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Calcasieu Project

HGEO authorized exports to FTA Nations for the Calcasieu Project in 2013 and 2014 and to Non-FTA Nations in March 2019 for a combined capacity of approximately 12.0 mtpa. All authorizations now extend through December 2050. DOE also amended the authorizations to include short-term commissioning exports, and approved an increase in authorized capacity to 12.4 mtpa in 2022 (FTA) and 2025 (Non-FTA).

Plaquemines Project

HGEO authorized exports to FTA Nations for the Plaquemines Project in July 2016 and to Non-FTA Nations in October 2019 for a total capacity of 24.0 mtpa, with terms extended through 2050. DOE later amended these authorizations to include short-term export authority for commissioning volumes, consistent with the Calcasieu Project. In March 2022, we requested an increase to 27.2 mtpa; DOE approved that higher capacity for FTA Nations in June 2022 and is reviewing the Non-FTA request. Following our December 2025 FERC filing to uprate capacity to 35.0 mtpa, we plan to submit a corresponding DOE export application in the first half of 2026.

Plaquemines Expansion Project

In November 2025, we filed a DOE application to export up to 31.0 mtpa from the Plaquemines Expansion Project to both FTA and Non-FTA Nations. The application is pending DOE action.

CP2 Project

HGEO authorized 28.0 mtpa of exports to FTA Nations in April 2022 and to Non-FTA Nations in October 2025 following completion of its review of the 2024 LNG Export Study. An appeal of the Non-FTA order by environmental groups remains pending. In February 2026, we submitted an application with the DOE to increase our authorized export volumes to FTA and non-FTA nations to 35.0 mtpa, to align with our uprate request filed with FERC in December 2025.

CP2 Expansion Project

As of December 31, 2025, no HGEO export application has been filed for the CP2 Expansion Project. We expect to seek authorization in parallel with our formal FERC application for the project.

CP3 Project

As of December 31, 2025, no HGEO export application has been filed for the CP3 Project. We expect to seek authorization in parallel with our formal FERC application for the project.

Department of Transportation Pipeline and Hazardous Materials Safety Administration

Our projects must comply with certain safety standards set by PHMSA. 49 C.F.R. Part 193, Federal Safety Standards for Liquefied Natural Gas Facilities, which establishes minimum federal safety standards for the siting, construction, operation, and maintenance of onshore LNG facilities and the siting of marine cargo transfer systems at waterfront LNG plants. These standards also incorporate by reference the National Fire Protection Association, Standard 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas.” Pursuant to a Memorandum of Understanding, or MOU, between FERC and PHMSA, PHMSA issues a Letter of Determination, or LOD, regarding compliance with the applicable safety standards for FERC jurisdictional LNG facilities, which is incorporated into the relevant FERC proceeding. Accordingly, PHMSA issued the requisite LOD for each of the Calcasieu Project (as well as its “uprate” amendment), the Plaquemines Project (and its first uprate), and the CP2 Project. PHMSA LODs will also be required for the Plaquemines Expansion Project and the uprate projects recently filed for both the Plaquemines Project and the CP2 Project, as part of each of the relevant FERC processes. Once

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constructed and operational, each of our LNG facilities’ compliance with the 49 C.F.R. Part 193 requirements will be subject to DOT’s inspection and enforcement program.

Other Governmental Permits, Approvals and Authorizations

The construction and operation of our projects is subject to additional federal and state permits, orders, approvals, and consultations required by other federal and state agencies, including the DOE, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Marine Fisheries Services, Federal Aviation Administration, U.S. Fish and Wildlife Service, EPA, Louisiana Department of Environmental Quality, Louisiana Department of Energy and Natural Resources, and U.S. Department of Homeland Security. We currently have all material permits required for our projects at their current respective stage of construction and operations. Permitting for the Plaquemines Expansion, CP2 Expansion, and CP3 projects remains ongoing.

Commodity Futures Trading Commission (CFTC)

We have entered into interest rate hedges, including interest rate swaps, in connection with our variable rate debt agreements, and we may enter into additional interest rate hedges and other derivatives in the future. Pursuant to authority granted by the CEA, the CFTC exercises federal oversight and regulation of the derivatives market in the United States for most types of derivatives and entities, like us, that participate in that market.

Among other CFTC requirements, the CFTC’s swaps rules impose a range of regulatory requirements on parties transacting in swaps that, among other things: (i) provide for the registration and regulation of Swap Dealers and Major Swap Participants; (ii) impose clearing and trade execution requirements for certain swaps, subject to certain exceptions; (iii) establish swaps recordkeeping and reporting regimes; and (iv) implement the CFTC’s anti-manipulation, anti-fraud, and anti-disruptive trade practice authority.

As a commercial end-user, we are subject to only limited CFTC swaps requirements. However, the application of these requirements to other market participants may affect the overall swaps market, including the costs and availability of the types of swaps we use to hedge or mitigate our commercial risks. In addition, the CFTC’s swap requirements remain subject to changes from future rule amendments, interpretive guidance and no-action relief, and the ultimate effect on our business of any changes to the rules or interpretive guidance, or of any new rules in the future, remains uncertain.

Environmental Regulation

Our projects are subject to various federal, state, and local environmental statutes and regulations intended to ensure the protection of the environment. In certain cases, these environmental laws and regulations require us to obtain permits and authorizations and engage in agency consultations prior to construction and operation of a project. Many laws and regulations restrict or prohibit the types, quantities, and concentration of substances that can be released into the environment. In addition, our LNG tankers are subject to environmental regulations, rules and conventions adopted in the jurisdictions in which they call or are flagged, including requirements to record and report their fuel consumption, and to purchase and surrender emissions credits. Similarly, our downstream sales of LNG into, for example, the European Union, are subject to environmental-based monitoring and reporting adopted in those jurisdictions. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. See Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating and/or construction costs and restrictions of this Form 10-K for more information.

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA)

Certain aspects of our projects may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, which provides for the investigation, cleanup, and restoration of natural resources from releases of hazardous substances (not including “petroleum”). We may be subject to liability

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under CERCLA as a result of contamination at properties currently or formerly owned, leased, or operated by us or our predecessors or at third-party contaminated facilities to which we have sent waste for treatment or disposal. Liability under CERCLA can be imposed on a joint and several basis and without regard to fault or the legality of the conduct giving rise to contamination.

Clean Air Act (CAA)

Our projects are subject to the CAA and comparable state and local laws. Under the CAA, the EPA has the authority to control air pollution by issuing and enforcing regulations for entities that emit substances into the air. The EPA has promulgated regulations for major sources of air pollution and has delegated implementation of these regulations to state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality. In addition to having obtained relevant air permits from the Louisiana Department of Environmental Quality prior to construction of our projects, we are subject to ongoing emissions standards, requirements, and reporting obligations under the EPA rules, as well as under Louisiana, and in the case of the CP Express Pipeline and the Blackfin Pipeline, Texas state regulatory agencies.

Coastal Zone Management Act (CZMA)

The Coastal Zone Management Act, or CZMA, is intended to ensure the effective management, beneficial use, protection, and development of the nation’s coastal zone. Under the CZMA, participating states are required to develop management programs demonstrating how they will meet their obligations and responsibilities in managing their coastal areas. The Louisiana Department of Energy and Conservation, which administers the CZMA for each of our projects, issued a coastal use permit and related mitigation plan for the Calcasieu and CP2 projects, and an exemption for the Plaquemines LNG terminal due to its location within an area designed by Louisiana law as “fastlands” and a “no direct or significant impact” (NDSI) exemption for the Plaquemines marine facility.

Clean Water Act (CWA) and Rivers and Harbors Act

Our projects are subject to the CWA, which regulates discharges of pollutants into the waters of the United States, as well as analogous state and local laws. Under section 401 of the CWA, a federal agency may not issue a permit for any activity that may result in any discharge into the waters of the United States unless the state where the discharge would originate either issues a water quality certification verifying compliance with existing water quality requirements or waives this requirement. Additionally, section 404 of the CWA regulates the discharge of dredged or fill material into waters of the United States, including wetlands. Each of the Calcasieu Project, Plaquemines Project, and CP2 Project has received a water quality certification from the Louisiana Department of Environmental Quality, Water Quality Division. The Calcasieu, Plaquemines and CP2 projects have received CWA section 404 permits and section 10 of the Rivers and Harbors Act from the U.S. Army Corps of Engineers, or USACE, and permits from the Louisiana Department of Environmental Quality for the discharge of stormwater arising in connection with construction activities and industrial operations once construction is complete, and the discharge of wastewater generated during the operation of the facility.

Resource Conservation and Recovery Act (RCRA)

Under the Resource Conservation and Recovery Act, or RCRA, and comparable state hazardous waste laws, the EPA and authorized state agencies, including the Louisiana Department of Environmental Quality and the Texas Commission on Environmental Quality, regulate the generation, transportation, treatment, storage, and disposal of hazardous waste. If hazardous wastes are generated or stored in connection with any of our projects, we would be subject to the requirements of such laws.

Endangered Species Act, or ESA, Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, and National Environmental Policy Act, or NEPA

Section 7 of the Endangered Species Act provides that any project authorized by any federal agency should not jeopardize the continued existence of any endangered species or threatened species, or result in the destruction or

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adverse modification of habitat of such species which is determined to be critical. The Magnuson-Stevens Fishery Conservation and Management Act, or MSFCMA, establishes procedures designed to identify, conserve, and enhance essential fish habitat for those species regulated under a federal fisheries management plan. During the FERC review process for each of our projects, we engaged in consultation with the relevant federal agencies pursuant to the ESA and MSFCMA. Such consultation was completed for the Calcasieu Project, the Plaquemines Project, and the CP2 Project, but has not yet begun for any other future projects or bolt-on expansions.

The issuance of requisite permits and authorizations for our projects may be subject to environmental review under the National Environmental Protection Act, or NEPA. NEPA requires federal agencies to evaluate the environmental impact of major agency actions that may significantly affect the quality of the human environment, such as the granting of a permit or similar authorization for the development of certain projects. As part of NEPA review, federal agencies will prepare either an environmental assessment or a more detailed environmental impact statement that assesses the potential direct, indirect and cumulative impacts of a proposed project and is made available for public review and comment. The NEPA review process can lead to significant delays in approving such projects and the issuance of requisite permits. As a result of its NEPA review, a federal agency may decide to deny permits or other support for a project, or condition approvals on certain modifications or mitigation actions.

In May 2024, the Council on Environmental Quality, or CEQ, published its final “Phase 2” NEPA regulations, which included specific direction to account for both climate change and environmental justice effects in NEPA reviews. However, in January 2025, President Trump issued an executive order directing CEQ to rescind existing NEPA regulations and issue guidance and coordinate agency level regulations implementing NEPA that expedites permitting and prioritizes energy production. In response, CEQ rescinded its implementing regulations for NEPA reviews through an interim final rule in February 2025 that was adopted as final in January 2026. In light of CEQ’s rescission of its NEPA regulations, DOE and FERC have revised their own regulations and guidelines governing their respective NEPA review process. Unlike the now-rescinded Phase 2 NEPA regulations issued by CEQ, these revised regulations and guidelines do not include requirements to account for climate change or environmental justice. The outcome and impact of these legal developments cannot be predicted at this time.

Seasonality

Seasonal weather can affect the need for our LNG sales. While we expect that a substantial amount of our LNG will be sold under long-term Contracted SPAs, we have experienced, and expect to continue to experience, the effects of market volatility and fluctuation in seasonal demand for LNG in our existing markets for our commissioning LNG sales. Additionally, excess LNG produced by our projects above the nameplate capacity that is sold to VG Commodities or otherwise can, to the extent not previously committed to third parties, be resold to third party customers at our discretion under short-, medium-, or long-term contracts, including on a forward spot basis, which would expose our revenues to such volatility and fluctuation in seasonal demand. Changes in temperature and weather may affect both power demand and power generation mix in the locations we service, including the portion of electricity provided through other sources of energy, such as hydroelectric, solar, or wind, thus affecting the need for regasified LNG. These changes can increase or decrease demand for LNG and accordingly, fluctuations in revenue during quarters of high and low demand, respectively, could have a disproportionate effect on our results of operations, especially with regard to the LNG sold into the spot market.

Competition

The global LNG and natural gas markets are highly competitive. We compete with many participants across an integrated supply chain, including independent LNG producers, commodities marketing and trading firms, national energy companies, utility companies, and major multinational energy companies, primarily over supplies of natural gas and sales of our LNG. We believe our proprietary mid-scale, factory-built liquefaction train design, project execution excellence, access to well-priced and abundant, domestically sourced natural gas, simultaneous construction and integrated operations approach, with its associated commissioning cargos and proceeds, capital strength, leadership, and mission and values-led culture position Venture Global well to compete and thrive against this diverse competitive landscape.

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We are subject to market-based price competition, reflecting supply and demand market pricing dynamics, with respect to revenue associated with any sales of our commissioning cargos and sales of LNG in excess of our nameplate capacity. We have experienced, and expect to continue to experience, competition with respect to LNG sales, including the effects of changes in supply and demand due to recent market volatility. The balance between the availability of LNG and the market demand for LNG significantly affects competition and the market price for our products. This dynamic is particularly acute for LNG sold on a forward spot or short-term contracted basis, such as any commissioning sales and excess capacity sales. Even after COD for our projects, we may continue to have a meaningful component of our production and sales subject to spot and short- or intermediate-term market dynamics. This may occur as a result of selling excess LNG production capacity through VG Commodities under short‑, medium‑, or long‑term arrangements,

Our current development projects, any future projects we develop, including expansions, will compete with other domestic and international suppliers, including other LNG projects being developed by us, on the basis of price per contracted volume of LNG.

With respect to our projects, our current and potential competitors include, but are not limited to, (1) national energy companies, such as QatarEnergy, (2) major multinational energy companies, including BP, Chevron, ConocoPhillips, ExxonMobil, Shell and Total, (3) independent LNG producers, including Cheniere and Freeport LNG, (4) utility companies, such as Sempra, and (5) commodities marketing and trading firms, such as Glencore, Trafigura, and Vitol. Some of our competitors may have financial, engineering, marketing, and other resources greater than we have, and some of them are fully integrated energy companies. Importantly, many of our competitors are also our customers with whom we have short-, intermediate-, and long-term contractual relationships.

Insurance

We maintain a comprehensive insurance program to insure potential losses to Venture Global and our projects from physical loss or damage, including due to floods and named windstorms, as well as third-party liabilities, during construction and subsequent operation. We expect to establish a similar comprehensive insurance program for our future development projects and bolt-on expansion projects at the appropriate and prudent time. We maintain a comprehensive insurance program to insure against customary risks and losses for our LNG tankers including protection and indemnity coverage and hull and machinery insurance as well as charterers’ liability insurance for our chartered LNG tankers. We may not be able to maintain adequate insurance in the future at rates that are considered reasonable. See Item 1A.—Risk Factors—Risks Relating to Our Business—We are unable to insure against all potential risks and may become subject to higher than expected insurance premiums. In addition, we retain certain risks as a result of insurance through our captive insurance of this Form 10-K.

Available Information

Our Class A common stock has been publicly traded since January 24, 2025 and is traded on the New York Stock Exchange under the symbol “VG.” Our principal executive offices are located at 1001 19th Street North, Suite 1500, Arlington, VA, 22209, and our telephone number is (202) 759-6740. Our internet address is www.ventureglobal.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Venture Global, Inc., Investor Relations, 1001 19th Street North, Suite 1500, Arlington, VA, 22209 or call (202) 759-6740. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers.

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ITEM 1A. RISK FACTORS

You should carefully consider the risks and uncertainties described below, together with all other information contained in this Form 10-K, including those discussed in I t em 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K. If any of the following risks were to occur, our business, financial condition, results of operations and cash flow could be materially adversely affected. The following risks are not the only ones facing our company. Additional risks and uncertainties not currently known to us, or that we currently deem immaterial, may also impair or adversely affect us.

Risks Relating to Our Business

Our ability to maintain profitability and positive operating cash flows is subject to significant uncertainty.

We will continue to incur significant capital and operating expenditures while we develop, construct, and commission our projects. Our ability to maintain profitability and positive operating cash flows is primarily dependent on our ability to generate proceeds, and in turn net profits and operating cash flows, through the sale of LNG commissioning cargos, the sale of excess LNG that is produced above the nameplate capacity of our LNG projects, and, after COD occurs for a given project, through the sale of LNG pursuant to our post-COD SPAs, as well as our ability to monetize our other assets (such as pipelines, LNG tankers and downstream regasification capacity).

For our projects that have yet to achieve COD, our ability to sell LNG commissioning cargos depends on our ability to successfully market, produce, load and, in some cases, deliver commissioning cargos during the commissioning of our projects prior to achieving COD. Although we have generated proceeds from the sales of commissioning cargos at the Calcasieu Project from first quarter of 2022 until COD was achieved in April 2025, and also at the Plaquemines Project since January 2025, such sales of commissioning cargos are limited in duration, and subject to a number of material uncertainties and risks. We are obligated to cease sales of commissioning cargos once the relevant COD occurs. The duration of the commissioning period at the Calcasieu Project, which was extended by a force majeure event, and the amount of proceeds we generated from the sales of commissioning cargos from the Calcasieu Project and also from the Plaquemines Project, may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any of our projects or expansions thereof for any future period. See —Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds, given significant volatility in spot-market prices and —Historical proceeds from commissioning cargo sales at the Calcasieu Project, which had an extended commissioning period due to unanticipated challenges with equipment reliability and which began producing LNG in a high-price environment, may not be indicative of the duration of the commissioning period or the amount of proceeds for any of our other projects or expansions thereof.

Our ability to generate sales of LNG at each project or expansion thereof following COD, depends on our ability to successfully commence and maintain deliveries under our post-COD SPAs for such project or expansion, and also on our ability to produce and sell LNG in excess of the nameplate capacity of such project or expansion. We will not generate any revenues or operating cash flow under our post-COD SPAs, or from sales to third parties of excess LNG that is produced above the nameplate capacity of our LNG projects, until we have achieved COD for the relevant project. In addition, such revenues may be subject to increased volatility when compared to our long term post-COD SPAs if we choose to enter into any shorter term SPAs or if we choose to sell any LNG in excess of the nameplate capacity of our projects on a spot or short term basis.

There is no guarantee that we will achieve COD for any of our projects or expansions thereof, within the anticipated timeframes or at all, including as a result of risks described elsewhere in these "Risk Factors", including —Risks Relating to Regulation and Litigation—We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects. As a result, there can be no assurance as to when we will commence deliveries under our post-COD SPAs, and therefore when, if at all, we will commence generating revenues and operating cash flows from our post-COD SPAs or from the sale of LNG produced in excess of nameplate capacity, if any, for our projects that have not yet achieved COD including any expansions thereof.

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In addition to our post-COD SPAs, we have also entered into certain Firm-start SPAs. Our ability to satisfy our obligations under such Firm-start SPAs following the applicable firm start dates will depend in part on our ability to produce sufficient LNG cargos, either before or after COD, or in excess of nameplate capacity. While we expect to produce sufficient LNG volumes prior to the start date of each Firm-start SPA, there can be no assurance that our projects or bolt-on expansions will not be delayed, in which case we may not produce sufficient LNG to meet our obligations under the relevant Firm-start SPAs.

Further, there can be no assurance that we will be able to produce excess LNG above the nameplate capacity of the facilities at our projects, either at our target level of excess LNG production or at all, nor, even if such excess LNG is produced, that we will be able to resell all of it to third party customers.

Our ability to monetize our other assets, including our pipelines, LNG tankers and regasification facility capacity depends on a variety of factors, including but not limited to market conditions in the natural gas and LNG industries, required regulatory and governmental approvals, and our ability to successfully market, produce, load and deliver commissioning cargos during the commissioning of our projects prior to achieving COD and our ability to generate sales of LNG following COD at our projects. Specifically, our ability to construct and successfully monetize our interstate and intrastate pipelines will depend, among other factors, on worldwide demand for LNG, as well as on our obtaining the necessary regulatory approvals for our projects currently under development. Additionally, while we expect several of our LNG tankers to service our single DPU post-COD SPA, our ability to monetize the remainder of our LNG tanker fleet will depend on the demand from LNG customers or, potentially, other charterers, as well as that from any future SPAs we may enter into where LNG is sold on a delivered basis, for the services of such LNG tankers.

As a result, there is significant uncertainty about our ability to maintain profitability and positive operating cash flows.

We have only a limited track record and historical financial information, and there is no assurance that our business will be successful over the long term.

We first generated proceeds from sales of commissioning cargos at the Calcasieu Project only in the first quarter of 2022, and prior to that we incurred significant losses from operations and negative cash flows from operations.

In addition, as of December 31, 2025, a significant portion of the proceeds we have generated were from sales of commissioning cargos from the Calcasieu Project and the Plaquemines Project, and may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any future period or for any of our other projects or expansions thereof, or of our future results of operations more generally.

Our limited operating history may limit your ability to evaluate our prospects because of our limited historical financial data, our unproven ability to maintain or increase our profitability and our positive cash flows and our limited experience in addressing issues that may affect our ability to manage the construction, operation or maintenance of liquefaction facilities and related assets. We face all of the risks commonly encountered by other growing businesses, including competition and the need for additional capital and personnel. As a result, any assessment you make about our current business and any predictions you make about our future success or viability may not be accurate. There is no assurance that our business will be successful over the long term.

Historical proceeds from commissioning cargo sales at the Calcasieu Project, which had an extended commissioning period due to unanticipated challenges with equipment reliability and which began producing LNG in a high-price environment, may not be indicative of the duration of the commissioning period or the amount of proceeds for any of our other projects or expansions thereof.

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The duration of the commissioning period and our ability to generate proceeds from the sale of commissioning cargos during such period is subject to significant risks and uncertainties relating to the development, construction and commissioning of our projects as discussed in these “Risk Factors.” In particular, it is both our intention and our obligation, under our post-COD SPAs, to undertake the construction of and complete our projects or phases thereof in a reasonable and prudent manner, which, depending on the circumstances, could extend or shorten the commissioning period for such projects or phases thereof during which we are able to generate such proceeds. Further, certain delays in the development of or construction of our projects and any issues with the construction of our projects could delay or otherwise adversely impact our ability to generate such proceeds during the commissioning of the relevant projects. At any of our projects or phases thereof, if the commissioning of certain equipment or integrated facilities is delayed or if COD occurs earlier than expected, the duration of time when we are able to generate proceeds from the sale of commissioning cargos may be shortened, which could adversely impact the volume of LNG produced during commissioning and our ability to generate proceeds from the sale of commissioning cargos.

Historical proceeds from the sale of commissioning cargos at the Calcasieu Project, which had an extended commissioning period due to unanticipated challenges with equipment reliability before COD occurred in April 2025, may not be indicative of the duration of the commissioning period or the amount of proceeds for any of our other projects or expansions. Although we have included targeted COD dates for certain of our projects and phases thereof, there can be no assurance that COD will not occur earlier or later than such targets. If COD occurs earlier than expected for a particular project or phase thereof, it would adversely impact our ability to generate proceeds from the sale of commissioning cargos, which, subject to market conditions, may otherwise be more valuable than the revenues earned under our post-COD SPAs.

Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds, given significant volatility in spot-market prices.

A key element of our business strategy is to generate proceeds from the sale of LNG at our projects during the construction and commissioning phases of our projects, prior to the relevant project achieving COD.

In addition to the duration of the commissioning period, our ability to generate such proceeds depends on our ability to negotiate sales during the construction and commissioning phases of each project. There is no assurance that we will be able to continue to successfully negotiate sales of such commissioning cargos on terms that are acceptable to us, or that we will be able to successfully market, produce, load and deliver such commissioning cargos from our projects in the future. In addition, because commissioning cargos are not sold under post-COD SPAs and are instead sold on varying terms, including in some instances on a forward basis, proceeds from such commissioning cargos may vary significantly depending on, among other factors, prices and market conditions in the international LNG markets, global LNG freight rates, and the timing of when a contract for sale is executed. As such, the amount of any proceeds that we may generate from the sale of commissioning cargos and our profitability relating to such sales is largely dependent on the strength of international LNG markets, as primarily reflected in the spot price for LNG at the time a contract for sale of commissioning cargos is executed. Historically, the spot price for LNG has varied significantly, which has impacted the amount of proceeds generated from the sales of commissioning cargos. Further, the proceeds that we generate during any given period of time may not necessarily correlate with the prevailing market prices for the corresponding period of time, given a variety of factors, including that we have and may continue to contract sales on a forward basis, at a pre-determined price.

As a result, we have experienced during the commissioning phase for the Calcasieu Project and the Plaquemines Project, and expect to continue to experience during the respective commissioning phase for our other future projects and expansions, significant volatility in the proceeds generated from the sales of commissioning cargos. Accordingly, the proceeds we have generated from such sales of commissioning cargos to date, may not be indicative of the duration of the commissioning period or the amount of proceeds from such sales for any of our other projects or expansions. As a result, such proceeds, and also our operating results more generally, may vary significantly from one fiscal period to the next comparable fiscal period. Moreover, if we are not able to generate proceeds from the sale of commissioning cargos in the future that are comparable to such historical proceeds

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realized, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity, and prospects.

Our ability to optimize sales of our LNG cargos is subject to significant uncertainty and volatility in proceeds generated from such sales.

Our business strategy includes applying cash proceeds from one project to decrease the financing required for future projects. Our strategy is to optimize sales of LNG produced following COD by committing certain nameplate capacity to long-term post-COD SPAs, with the aim of creating a base of stable cash flows, while reserving the rest of a project’s nameplate capacity, as well as its potential excess capacity, to sell on a short-, medium-, or long-term basis with the goal of optimizing pricing for such capacity and balancing profit, duration and risk.

Our ability to optimize sales of LNG cargos that are not otherwise committed depends on our ability to negotiate sales that meet our objective of balancing profit, duration and risk. There is no assurance that we will be able to successfully negotiate sales of such cargos on terms that are acceptable to us. In addition, because such cargos may be sold on varying terms, including in some instances on a forward basis, proceeds from such cargos may vary significantly from period-to-period and from project-to-project depending on, among other factors, prices and market conditions in the international LNG markets, domestic natural gas markets, global LNG freight rates, and on the timing of when a contract for sale is executed. Further, the amount of any proceeds that we may generate from such sales, and our profitability relating to such sales, is largely dependent on the strength of international LNG markets, as primarily reflected in the spot price for LNG at the time a contract for sale of such cargos is executed, as well as the availability and pricing of feed gas. Historically, the spot price for LNG has varied significantly, as have domestic natural gas prices, and we expect these prices will continue to vary significantly in the future which will impact the amount of proceeds we generate from such sales. Further, we may at times contract such cargos on a forward basis and, as a result, such sales may be uncorrelated with movements in spot LNG prices.

As a result, we may experience significant volatility in any proceeds we generate from sales of post-COD LNG cargos at our projects, in particular if we reduce the proportion of such cargos that are committed under long-term SPAs. Moreover, if we are not able to effectively optimize sales of such cargos in the future, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We have not entered into SPAs with customers for the total expected nameplate capacity at Phase 2 of the CP2 Project, or other future projects or expansions, and our failure to enter into final and binding contracts for an adequate portion of, or to otherwise sell, the expected nameplate capacity of any of our projects, including any phases or expansions thereof, could impact our ability to take FID for such projects.

Our ability to generate revenue and cash flow is partially based on our ability to enter into long-term SPAs with customers with respect to the expected nameplate capacity of our projects. Changes in market conditions relating to, among other factors, the price of natural gas in the United States and the price of LNG in international markets could adversely affect the competitiveness of our projects and our ability to enter into such SPAs, which could adversely impact our potential revenues.

We are actively marketing a portion of the remaining expected nameplate capacity of Phase 2 of the CP2 Project to leading international oil and gas companies, national and multinational utilities and LNG portfolio trading companies. As of December 31, 2025, Phase 2 of the CP2 Project has contracted to sell 1.0 mtpa of LNG under a 20-year SPA. The obligation to make LNG available under the post-COD SPAs commences from the occurrence of COD for Phase 2 of the CP2 Project. Additionally, we contracted through VG Commodities to sell 2.5 mtpa of LNG under 20-year Firm-start SPAs, which are expected to be transition to CP2 upon COD of Phase 2 of the CP2 Project.

As of this date, we have not entered into any SPAs for any of our other future projects or expansions and have not yet begun actively marketing the expected nameplate capacity for such other future projects or expansions. While taking FID for a given project, including any phase or expansion thereof, is subject to numerous factors, we

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may elect to proceed with FID for Phase 2 of the CP2 Project, or any other future projects, including any phases or expansions thereof, only after we execute binding SPAs for such projects, phases, or expansions, that cover a targeted portion of the applicable nameplate capacity that we consider adequate to support the development and financing of such project, phase, or expansion. Our inability to take FID for any future development project or any phase or expansion thereof may result in a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and, prospects.

Our revenues and operating margins may be adversely affected if we are unable to produce and sell liquefaction capacity in excess of the nameplate capacity of our facilities.

A key element of our business strategy is to generate revenue from the sale of LNG produced at each of our projects in excess of the nameplate capacity of the relevant project after such project achieves COD.

We aim to develop and operate our LNG facilities to be capable of producing greater excess capacity at each of our projects, in some cases by as much as 40% of their guaranteed nameplate capacity. Our ability to produce LNG in excess of the nameplate capacity at each of our projects is subject to significant risks and uncertainties relating to the development, construction and commissioning of our projects as discussed in these “Risk Factors.” Although we believe that our design and configuration will enable us to produce excess LNG without incurring material additional operating expenses or requiring additional capital investment, we may encounter additional, unforeseen costs, resulting in either operating expenses or capital investment, that make production of any excess LNG less economic or, potentially, uneconomic. Any increase in our incremental operating expenses or capital investments could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. As a result, there can be no assurance that we will be successful in producing any such excess LNG at any of our projects on a consistent and reliable basis, or at all.

We generally plan to retain flexibility to sell any excess LNG on a spot basis, or on a short-, medium- or long-term basis. Our ability to sell any such LNG will be subject to a number of risks and uncertainties outside our control, and there can be no assurance as to when, or on what terms, we will be able to sell any such excess LNG, if at all. As a result, revenues from the sale of any such excess LNG may vary significantly depending on prices and conditions in the international LNG markets and depending on when a contract for sale is executed, and the terms of those contracts may not always be favorable.

To the extent we are unable to sell such excess LNG, our revenues will be adversely impacted, and any such impact could be significant. In addition, we will likely still be required to pay certain of our operating expenses related to the anticipated production of such excess LNG (such as pipeline transportation costs incurred to transport natural gas for the production of such excess LNG) without generating any corresponding revenue. As a result, any such shortfall would also reduce our operating margins. Any of the foregoing could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

In addition, VG Commodities has contracted to resell at least 50% of the LNG generated post-COD by the Calcasieu Project in excess of that project's nameplate capacity (subject to an annual cap at the option of the counterparty). Pursuant to such agreement, the counterparty is entitled to an assignment of VG Commodities’ rights under the applicable intercompany excess capacity SPA in certain cases (including but not limited to when an event of default by VG Commodities has occurred and not been cured pursuant to such agreement with the counterparty). VG Commodities has also contracted to resell LNG generated by one or more of our other projects in excess of their respective nameplate capacities (excluding the 50% of the LNG generated by the Calcasieu Project) on a long-term basis. We may enter into similar arrangements related to the excess LNG at our other projects, including bolt-on expansions thereof, in the future.

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Our customers or we may terminate our SPAs if certain conditions are not met or for other reasons.

Each of our SPAs contains or will contain various termination rights allowing our current and future customers to terminate, or be relieved from their contractual obligations under their SPAs including, without limitation:

•with respect to certain post-COD SPAs, the failure of certain conditions precedent to be satisfied or waived by a specified date, or delays in the occurrence of COD beyond a specified time period;

•if we fail to make available specified scheduled cargo quantities;

•upon the occurrence of certain extended events of force majeure;

•if we have been held liable in excess of certain liability caps and we did not agree to increase such liability caps as specified under the relevant SPA;

•our failure to satisfy our contractual obligations after an event of default and after any applicable cure periods; and

•the occurrence of certain change of control events.

While we could potentially replace any SPAs that are terminated by our customers or us, we may not be able to replace these SPAs on similar or favorable terms, or at all, if they are terminated. Further, under certain financing agreements, we may be required to maintain in effect (subject to our ability to replace them over a certain period of time that may extend up to 180 days) certain long-term SPAs for a particular project, and any breach of such requirement after the applicable grace period may, unless certain prepayments are made, result in an event of default under such agreements, as well as a cross-default under our other financing agreements for that project or otherwise. As a result, a termination of certain SPAs could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our ability to generate cash under our Contracted SPAs and sales by VG Commodities is substantially dependent upon the performance by a limited number of our customers, and we could be materially and adversely affected if certain of these customers fail to perform their contractual obligations for any reason.

We currently have and expect to continue having a limited number of customers to whom we sell LNG under our Contracted SPAs and sales by VG Commodities. For example, as of December 31, 2025, we have executed 47.0 mtpa of post-COD SPAs and Firm-start SPAs with 24 customers with respect to LNG from our projects, of which 45.2 mtpa is contracted on a 20-year basis and 1.8 mtpa is contracted on a short- and medium-term basis. For the year ended December 31, 2025, approximately 50.0% of our revenue for the period from individual external customers was concentrated across three customers. Moreover, for the year ended December 31, 2025, we had one customer which represented approximately 23% of our revenue for that same period.

The ability of our customers to perform their respective obligations to us will depend on numerous factors that are beyond our control. Our future results, our ability to service any debt we may incur and our liquidity are substantially dependent upon the performance of these customers under their contracts, and on such customers’ continued willingness and ability to perform their contractual obligations. We are also exposed to the credit risk of any guarantor of the customers’ obligations under their respective agreements if we must seek recourse under a guaranty. Any such credit support may not be sufficient to satisfy the obligations in the event of a counterparty default. In addition, if a controversy arises under an agreement resulting in a judgment in our favor where the counterparty has limited assets in the United States to satisfy such judgment, we may need to seek to enforce a final U.S. court judgment or arbitral award in a foreign tribunal, which could involve a more lengthy and less certain process and also result in additional costs.

Certain of our existing SPAs limit, and our future SPAs may limit, the liability of the relevant customer or its guarantor (or both). As a result, if a customer fails to perform its obligations under an LNG sales contract (including, for example, by failing to take or pay for the contracted volume of LNG), our ability to recover from that customer or from any guarantor of its obligations would be subject to any agreed upon limitations on liability. In

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addition, our existing SPAs excuse, and we expect that our future SPAs will excuse, performance by our customers upon the occurrence of force majeure events, such as certain severe adverse weather conditions, the breakdown or failure of its LNG tankers and acts of God.

Failures by certain of our customers to perform their obligations, or our inability to recover from such customers or the applicable guarantors, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our operating margins may be adversely affected if the price of natural gas decreases, if we pay a premium for feed gas relative to the contractual spot price we charge our customers, or as a result of inflationary pressures.

Our post-COD and other SPAs typically require, and we expect our future SPAs will require, our customers to pay a fee equal to a fixed liquefaction fee per MMBtu, plus an amount equal to, depending on the applicable SPA, 115% or more of the Henry Hub price for feed gas that covers the cost of feed gas and is intended to cover gas transportation costs and certain of our other operating expenses. As a result, any decrease in the price of feed gas may reduce our operating margins under our SPAs.

In addition, there can be no assurance that the terms of our SPAs will pass through the actual price we pay for the supply and transport of feed gas to produce LNG under such SPAs. While we expect to manage our portfolio of gas supply to match the Henry Hub price we charge our customers under SPAs, there can be no assurance that we will be able to do so, particularly in times of volatility in the price of natural gas. If we are required to purchase feed gas at a premium relative to the Henry Hub price used to calculate the fee under the relevant LNG sales contract due to unexpected market factors or otherwise, our operating margins would be reduced.

Similarly, under certain SPAs for the sale of commissioning cargos and certain sales by VG Commodities, our customers pay a fixed fee or a fee based on an index other than Henry Hub (such as the TTF or JKM benchmarks), and in such cases our operating margins may be reduced in the event of an increase in the price at which we are required to purchase feed gas relative to the relevant fixed fee or alternate index, or in the event of a reduction in the price of the relevant index used to calculate the fee under the relevant SPA relative to the price at which we are required to purchase feed gas.

We also anticipate that certain Contracted SPAs and certain sales by VG Commodities we enter into will include a fixed fee that will only be partially adjusted for inflation over the contract term. As a result, inflationary pressures over time will not be fully reflected in the prices we charge our customers under such sale agreements. At the same time, our operating expenses are likely to increase due to inflationary pressure. Any such increases may not be fully offset by any partial inflation adjustments under our Contracted SPAs or certain sales by VG Commodities and, as a result, inflation may reduce our operating margins.

Any reduction in our operating margins as a result of these factors could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Natural gas producers may curtail or shut in production due to market, pricing or other conditions, which could reduce the availability of feed gas for our LNG facilities.

We depend on third-party natural gas suppliers to provide the natural gas necessary to operate our liquefaction facilities. Significant sustained declines in natural gas prices, oversupply in natural gas markets or crude, or materially adverse changes in the cost structure or profitability of upstream producers could cause producers to shut-in, curtail or reduce production from existing wells and defer or cancel planned drilling activity. Natural gas supply curtailments or shut-ins, whether due to low commodity prices, operational constraints, government actions, weather, or other market conditions, could limit the volume of natural gas available to us, and may significantly increase our feed gas costs, constrain our ability to operate our facilities at expected utilization levels, and have a material adverse effect on our business, financial condition, results of operations and future growth prospects.

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In periods of low or volatile natural gas prices, producers may elect to reduce output from higher-cost wells or delay completion of drilled but uncompleted wells, which may lead to reduced supply in the natural gas markets where we obtain our feed gas. Such supply variability could, among other things, result in increased competition for available natural gas supplies and reduced reliability of delivery commitments from suppliers. Our inability to obtain sufficient natural gas on commercially reasonable terms, or at all, could adversely affect our relationships with our customers and counterparties, who rely on us to deliver contracted volumes of LNG.

Additionally, regulatory actions, pipeline infrastructure constraints, extreme weather events, or other force majeure occurrences affecting our supply regions could exacerbate upstream production curtailments and further limit the availability of natural gas. While we seek to mitigate these risks through long-term supply arrangements, portfolio diversification and pipeline connectivity, there can be no assurance that such measures will fully protect us from the effects of upstream production slowdowns or curtailments. Any prolonged or widespread reduction in upstream natural gas production could have a material adverse effect on our business, financial condition, results of operations and future growth prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

We depend upon third-party pipelines to provide gas delivery options to our projects and any other natural gas liquefaction and export facilities that we may decide to develop in the future. We have entered into several precedent and service agreements with interstate pipeline companies to provide the natural gas transportation to the Calcasieu, Plaquemines, and CP2 Projects. We will need to enter into and secure additional pipeline transportation capacity for our other future projects and and expansions, for us to generate the expected nameplate and excess capacity of LNG at such projects or expansions. There can be no assurance that we will be able to enter into the requisite agreements to secure natural gas transportation capacity for our future projects and expansions on terms acceptable to us, or at all, which would impair our ability to fulfill our obligations under SPAs. Even if we have entered into the requisite agreements for our projects, there can be no assurance we will be able to secure the necessary natural gas transportation capacity for each of our projects.

In addition, we depend on third-party natural gas suppliers to provide the feed gas required to generate the expected nameplate and excess capacity of LNG at our projects. We anticipate that we will establish and maintain a portfolio of natural gas supply agreements or contracts to meet our requirements for the Calcasieu, Plaquemines and CP2 projects, and for our other future projects or expansions, but there can be no assurance that we will be successful in doing so on a long-term basis.

We also cannot control the regulatory and permitting approvals or third parties’ construction times, either with respect to capacity that has been secured or capacity that will be secured. If and when we need to replace one or more of our agreements with these interconnecting pipelines or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all, which would, in turn, impair our ability to fulfill our obligations under certain of our SPAs. Our failure to purchase or receive physical delivery of sufficient quantities of natural gas could prevent us from producing LNG or meeting our obligations under our SPAs and our ability to generate revenue would be adversely affected, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. In addition, if we are unable to deliver any contracted volume in full, our customers will generally be entitled to reimbursement of some or all costs and expenses for replacement LNG.

Certain metrics that we track and may present are illustrative and are subject to a number of assumptions, and any real or perceived inaccuracies in such metrics may adversely affect our business and reputation.

We track and may present from time to time certain metrics that are illustrative and not independently verified by any third party. Such metrics may be based on a range of assumptions, such as the development, completion and commissioning of the relevant projects (including obtaining any required regulatory approvals), estimated contracted

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volume for such project’s existing post-COD SPAs, assumed rate of inflation, and an assumed Henry Hub gas price per MMBtu, the occurrence of certain environmental conditions and the composition of feed gas. Such assumptions are based upon our management’s assessment of market comparables and other indicative pricing in the market and will be affected by various factors, including actual inflation rates and Henry Hub gas prices during the term of the relevant SPAs, performance by our customers under the applicable SPAs, as well as by the various risks and uncertainties relating to development, construction, commissioning and operation of our projects (including obtaining any required regulatory approvals) as described in this “Risk Factors” section. If such metrics are not accurate representations of our business, if investors do not perceive such metrics to be accurate, or if we discover material inaccuracies with respect to these figures, investors may lose confidence in our metrics and business and we could be subject to legal claims, including securities class action lawsuits, business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects could be affected. Our methodologies for calculating these metrics have a number of limitations and may change over time, which could result in unexpected changes to our metrics, including the metrics we publicly disclose.

We may not be successful in pursuing expansion opportunities at our current or future projects, which would adversely impact our growth prospects.

A key element of our growth strategy is to increase the liquefaction capacity at certain of our current and future projects through expansions that involve adding incremental liquefaction trains and certain related equipment to the relevant project. Our ability to pursue any such bolt-on expansion is subject to a number of risks and uncertainties and there can be no assurance that we will be able to complete all or some of our currently anticipated bolt-on expansion opportunities.

In particular, expansion opportunities are subject to regulatory approval, and as of the date of this Form 10-K, we have only recently submitted applications to FERC and DOE for the Plaquemines Expansion Project and we have not otherwise made any filings with the necessary regulators, including DOE or FERC, with respect to any other expansion opportunities at our current or future projects. Such approvals are subject to numerous risks and uncertainties as described under —Risks Relating to Regulation and Litigation, and there can be no assurance that we will be successful in obtaining any such regulatory approvals. In addition, we are evaluating contracting and optimal financing options for any expansions as there can be no assurance our projects will generate sufficient cash proceeds to fund all of the expansion opportunities we have identified at our current and future projects. Further, any expansions will require sufficient additional natural gas supply at the relevant project, and there can be no assurance we will be able to enter agreements for supply or transportation of the requisite natural gas on terms acceptable to us or at all.

Additionally, the development and construction of any expansions at our current or future projects could have an adverse effect on the ongoing or future construction, commissioning or operations, as applicable, of the relevant projects. The simultaneous construction and subsequent commissioning of any expansion opportunities at any project while such project is otherwise in construction, commissioning, or operating at full capacity, could subject us and our third-party contractors to additional safety risks, as well as additional costs related to the management of those safety hazards and additional required regulatory approvals. Any such additional safety or other measures and approvals could result in additional costs, could delay our plans for any such expansions, or could result in a smaller size of any potential expansion opportunity.

If we are not successful in pursuing expansion opportunities that we have identified at our projects, or if any such expansion opportunities are executed only at a smaller scale or on a delayed timeline, our growth would be adversely impacted. Any of the foregoing could have an adverse effect on our growth, financial condition, operating results, and cash flow.

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Seasonal fluctuations will cause our business and results of operations to vary among quarters, which could adversely affect our business and results of operations.

Our results of operations have fluctuated on a quarterly basis in the past, and may continue to fluctuate in the future, due to a wide variety of factors, including but not limited to the volatility in pricing and the seasonal nature of demand for natural gas and LNG, third-party supply disruptions, price spread between European and Asian LNG indices, the availability of, and associated freight rates of, LNG tankers and temperature and weather conditions across the markets we supply, which can have an impact on the demand for energy and, consequently, LNG. Accordingly, fluctuations in revenue during quarters of high and low demand, respectively, could have a disproportionate effect on our results of operations for the entire year. Thus, comparisons of our results of operations across different fiscal quarters may not be accurate indicators of our future performance. Annual or quarterly comparisons of our results of operations may not be useful, and our results in any particular period will not necessarily be indicative of the results to be expected for any future period. While we believe that our results of operations and earnings potential should be analyzed on a longer term view due to the nature of our business, such fluctuations can adversely affect our business and results of operations.

Our limited diversification could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Substantially all of our revenue is, and we expect will continue to be, dependent upon our LNG projects, all of which are currently located in southern Louisiana. Due to our limited asset and geographic diversification, an adverse development at the terminal or pipeline for our projects (including, for example, natural or man-made disasters affecting Louisiana, or significant long-term equipment failures), or in the natural gas or LNG industries, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

In the ordinary course of our business, we explore acquisitions and other targeted investments in areas of the natural gas industry that relate to our natural gas liquefaction and export projects that could negatively affect our operating results, increase our debt or cause us to incur significant expense.

An element of our strategy is to support our LNG growth through targeted transactions in areas of the natural gas industry that relate to our natural gas liquefaction and export projects. We intend to continue to explore targeted investments and acquisitions in the natural gas industry that complement and strengthen our project portfolio and solidify access to, and transport for, natural gas molecules, and the ability to deliver LNG, at commercially attractive terms. For example, we have in the past acquired firm regasification facility capacity at LNG regasification terminals in the United Kingdom and Greece. While we believe that these contracted regasification capacities will allow us to supply both LNG and regasified natural gas directly into the European market to current and future downstream customers and allow us to continue to grow our presence in the European markets, we cannot guarantee that demand for delivered LNG or regasified natural gas will be in line with our expectations.

We have limited experience with pursuing such expansions of our business through acquisitions or investments, which may be in areas to our business that relate to our natural gas liquefaction and export projects. Such acquisitions or investments may expose us to new risks not presently faced by our business. If we make any acquisitions, we may not be able to integrate these acquisitions successfully into our existing business, and we could assume unknown or contingent liabilities. In addition, we may enter into agreements with counterparties outside the U.S., which would expose us to political, governmental, and economic instability, foreign currency exchange rate fluctuations and corruption risk, all of which could be exacerbated by our lack of experience doing business in such other markets. Any future acquisitions also could result in the incurrence of debt, potential violations of covenants in our debt instruments, contingent liabilities, insufficient revenue acquired to offset liabilities assumed, unexpected expenses, inadequate return of capital, regulatory or compliance issues, potential infringements, difficulties integrating such acquired companies into our operations, and other unidentified issues not discovered in due diligence or future write-offs of intangible assets or goodwill, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. Integration of an acquired company also may disrupt ongoing operations and require management

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resources that we would otherwise focus on developing our existing business and projects. We may experience losses related to investments in other companies, and we may not realize the anticipated benefits of any acquisition, strategic alliance or joint venture. Accordingly, if such initiatives are not successful, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Severe weather events, hurricanes, or other disasters could result in an interruption of our operations, a delay in the completion of our projects, higher construction costs and the deferral of the dates on which we would become entitled to receive payments under any SPAs, all of which could adversely affect us.

Severe weather, including hurricanes and winter storms, can be destructive, causing construction delays, outages and property damage that require incurring additional expenses. Furthermore, our operations could be adversely affected, and our physical facilities could be at risk of damage, should changes in global climate produce, among other conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and severe weather events, abnormal levels of precipitation or a change in sea level or sea temperatures. Although the current design of each of our projects includes perimeter walls to protect against storm surge, there can be no assurance that they will be effective to protect against any of these events. In particular, all of our LNG projects that are currently under construction or development are in Southern Louisiana, which has historically been exposed to severe weather events and hurricanes. For example, in August and October 2020, respectively, Hurricanes Laura and Delta struck the Louisiana coast, with Hurricane Laura passing directly over the Calcasieu Project site.

Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, our projects or related infrastructure, as well as delays or cost increases in the construction and the development of our projects and following the completion of our projects, interruption of operations of our projects. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods, and rising sea levels. If any such effects were to occur, they could have a material adverse effect on our operations.

We are unable to insure against all potential risks and may become subject to higher than expected insurance premiums. In addition, we retain certain risks as a result of insurance through our captive insurance.

Although we have obtained certain customary insurance coverage in respect of the Calcasieu, Plaquemines, and CP2 projects, and our LNG tankers, we do not currently maintain insurance with respect to most aspects of the development, construction or operation of our other projects. We expect to obtain insurance as required under our contracts and consistent with industry standards (subject to availability on commercially reasonable terms) to protect against certain construction, operating and other risks, but not all risks will be insured or are insurable (for example, losses as a result of force majeure, natural or man-made disasters, terrorist attacks or sabotage or environmental contamination may not be available at all or on commercially reasonable terms). However, there can be no assurance that such insurance coverage will be available in the future on commercially reasonable terms or at commercially reasonable rates, or on the same or substantially similar terms as our existing insurance coverage or that the insurance proceeds will be adequate to cover the repair or replacement of equipment and materials, to cover lost revenues from our projects, or to compensate for any injuries or loss of life. Further, we use a captive insurance subsidiary to insure certain risk related to named windstorms and such coverage involves retaining certain risks that might otherwise be covered by traditional insurance. If certain operating risks occur, or if there is a total or partial loss of a project in the future, there can be no assurance that the proceeds of the applicable insurance policies will be adequate to cover lost revenues, increased expenses or the cost of repair or replacement. Additionally, in the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay claims. Any increases in the number or severity of claims or any such loss that is not covered by our insurance policies could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We anticipate that insurance premiums for LNG projects may increase due to a continuing increase in demand by LNG projects seeking insurance coverage, and losses and claims that have arisen or been experienced in

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respect of other unrelated projects in other regions or losses and claims that are large enough to impact the broader insurance market. Furthermore, we anticipate insurance premiums for projects located in Louisiana may increase significantly following the occurrence of future major hurricane damage in the region. Changes in global climate may produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and severe weather events, abnormal levels of precipitation or a change in sea level or sea temperatures. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in further increases in insurance premiums. Any such increases in premiums could be significant and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

A major health and safety incident relating to our business could be costly in terms of potential liabilities and reputational damage.

Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance may result in personal harm or injury, damage to property, fines or penalties for non-compliance with relevant regulatory requirements or litigation, and a failure that results in a significant health and safety incident is likely to be costly in terms of potential liabilities. Such a failure could generate public concern and have a corresponding impact on our reputation and our relationships with relevant regulatory agencies and local communities.

Failure to retain and attract executive officers and other skilled professional and technical employees or increased labor costs could have a material adverse effect on our operations.

Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled management employees for our various business and administrative operations is high. In addition, demand for skilled professional, technical and operations employees is high in the fields of engineering, construction, operations and gas transportation. Demand for these employees is high due to growth in demand for natural gas, increased supply of natural gas as a result of developments in gas production, increased infrastructure projects, and increased regulation of these activities. There can be no assurance that we will successfully recruit or retain qualified personnel, and our inability to retain and attract these employees could adversely affect our business and future operating results.

Furthermore, while most of our executive officers are required to devote substantially all of their time to our business, if other business interests of our executive co-chairmen require them to devote substantial amounts of time elsewhere, it could limit their ability to devote time to our business which may have a negative impact on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our operating results depend in significant part upon the continued contributions of key senior management and technical personnel. Continued successful operation of our projects and management of growth requires, among other things:

•continued development of financial and management systems;

•implementation of adequate internal control over financial reporting and disclosure controls and procedures;

•hiring and training of new personnel; and

•coordination among logistical, technical, accounting, finance, information technology, administrative, and commercial personnel.

An inability to successfully manage any of these factors could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity, financing requirements and prospects.

We are dependent on the strategic direction of Michael Sabel, our Chief Executive Officer, Executive Co-Chairman of the Board and Founder, and Robert Pender, our Executive Co-Chairman, Executive Co-Chairman of the Board and Founder.

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Mr. Sabel and Mr. Pender are, through VG Partners, our controlling shareholders, and therefore have significant influence on, and are drivers of, our business planning, strategy, and culture. Our success depends to a significant degree on their leadership, long-term vision, relationships, knowledge of the industry, and ability to execute our overall business strategy. If either Mr. Sabel or Mr. Pender were to discontinue their service with us due to death, disability or any other reason, it could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We and our contractors, including our EPC contractors, may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us.

Before construction of any project begins, we and our contractors, including our EPC contractors, need to hire new on-site employees to manage the construction of each project. In addition, before any of our projects commences operations, we need to hire an entire staff to operate the applicable facility. As a result, we expect the number of our personnel and our related costs to continue increasing significantly as we grow. If we and our contractors, including EPC contractors, are not able to attract and retain qualified personnel, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Construction, operation and maintenance of our facilities requires highly skilled personnel. There may be a limited supply of such personnel as a result of many factors, including intense competition to attract and retain the services of such persons. This competition may increase as additional LNG projects and other large-scale infrastructure projects are developed and constructed in North America, and in particular, the Gulf Coast of the United States. As a result, we and our contractors, including EPC contractors, may face shortages of qualified labor to construct, manage and operate our facilities, higher than anticipated labor costs or an inability to monitor, motivate and retain qualified personnel. An inability to recruit and retain such individuals could decrease productivity in the construction of our projects and in our operations. Competition for skilled employees could require us and our contractors, including EPC contractors, to pay higher wages, which could also result in higher labor costs.

Moreover, a shortage in the labor pool of skilled workers and other general inflationary pressures, which we and our contractors, including EPC contractors, have experienced in the past, and may continue to experience in the future, or changes in applicable laws and regulations could make it more difficult to attract and retain qualified personnel and could require an increase in the wage and benefits packages that are offered, thereby increasing our operating costs. Any increase in our operating costs could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We use and are planning to utilize various tax incentive programs the State of Louisiana offers that may not continue to be available or may be available in diminished form.

The State of Louisiana has various programs in place to incentivize investment in the state. These include sales tax rebates or exemptions, payroll tax credits, investment tax credits, inventory tax credits, and property tax exemptions. We have utilized such tax incentives where available for our existing projects and are planning to seek these tax benefits as well as any other tax benefits available to our other projects, including bolt-on expansions thereof. However, owing to the fiscal difficulties the state has faced in recent years, some of these programs have come under scrutiny and, as a result, the benefits provided by those programs have been reduced. In addition, applicants for these benefits have been subjected to greater scrutiny by the state, and have been subjected to a greater burden in demonstrating that they meet the criteria (such as job creation requirements) for the award of such benefits. Furthermore, the grant of certain of these benefits may be challenged in court.

If such lawsuits were to prevail or we are otherwise unable to secure the benefit of any of these incentive programs, or if there are further reductions to the benefits provided by these incentive programs, the financial performance and results of operations and our plans for our projects may be adversely impacted.

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Risks Relating to the LNG Industry

Competition in the LNG industry is intense, and certain of our competitors may have greater financial, engineering, marketing and other resources than we have.

We operate in the highly competitive area of LNG production, and we face intense competition from independent, technology-driven companies, national oil companies and major independent oil and natural gas companies and utilities. Certain of our competitors may have financial, engineering, marketing and other resources substantially greater than we have, and some of them are fully integrated oil and gas companies. Certain of these competitors also have longer operating histories, more development experience, greater name recognition, larger staffs, greater access to natural gas and LNG supply, and substantially greater financial, engineering, marketing and other resources than we do. In some cases, they may have also fully recouped the development and construction costs of their facilities. Our competitors’ superior resources or financial position could allow them to compete successfully against us, including by increasing their LNG production, decreasing their LNG prices, offering LNG transportation or otherwise. Our ability to compete in this highly competitive environment will depend in part upon our ability to successfully develop, construct and operate our projects, including any bolt-on expansions thereof, and any other natural gas liquefaction and export facilities that we may develop in the future, and our ability to enter into SPAs or otherwise sell LNG. Increases in the production of LNG by our competitors, or decreases in their LNG prices, could have a material adverse effect on the viability of any of our planned projects and on our ability to compete with them successfully. If we are unable to compete successfully with these companies, our business, financial condition and results of operations could be adversely affected.

We face competition based upon the international market price for LNG.

Our projects are and will be subject to the risk of LNG price competition at times when we need to replace any existing post-COD SPA, whether due to natural expiration, default or otherwise, and at times when we seek to sell or enter into additional SPAs with respect to our respective projects’ commissioning cargos and LNG that is produced in excess of the volumes required under our existing SPAs. Factors relating to competition may prevent us from entering into a new or replacement post-COD SPA on economically comparable terms as existing post-COD SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our projects and any other natural gas liquefaction and export facilities that we may decide to develop in the future are diverse and include, among others:

•increases in worldwide LNG production capacity and availability of LNG for market supply;

•lower than expected global economic growth and decreased demand for energy, including LNG, or increases in demand for LNG but at levels below those required to maintain a price equilibrium with respect to the cost of supply;

•increases in the cost to supply natural gas feedstock to our projects;

•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

•increases in capacity and utilization of nuclear power, renewable power, and related facilities outside the United States;

•political instability in foreign countries that import LNG, increased tariffs, or strained relations between such countries and the United States;

•displacement of LNG by new discoveries of gas, pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available; and

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•any events, developments or public statements, including by competitors or customers, that adversely impact our reputation.

Failure of LNG exported from the United States, including from our projects, to remain a competitive source of energy for international markets could adversely affect the LNG business of our customers, which could have a material adverse effect on their ability and willingness to perform under their Contracted SPAs with us, other sales by VG Commodities, or otherwise contract with us, and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Operations at our projects will be dependent upon the ability of our customers to deliver LNG supplies from the United States, including our projects, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan and the commercial operations of our projects, or any other natural gas liquefaction and export facility that we may decide to develop in the future, is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

Political instability in foreign countries that import or export natural gas, increased tariffs, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the United States. Conversely, future policy change in laws or regulation in the United States could restrict or limit natural gas exports to certain countries or in general.

In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. LNG from our projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from our projects in certain markets. The cost of LNG supplies from the United States, including our projects, may also be impacted by an increase in natural gas prices in the United States. Although our customers may elect not to incur these costs by not lifting or electing not to take delivery of certain scheduled LNG cargos, they are obligated to pay the fixed liquefaction fee under the relevant SPA for their scheduled quantities. However, such commercial conditions could cause customers to seek alternatives to satisfying this obligation under their SPAs.

As a result of these and other factors, LNG may not be a competitive source of energy internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our customers could adversely affect the ability of our customers to deliver LNG from the United States or from our projects on a commercial basis, which could have a material adverse effect on their ability and willingness to perform under their Contracted SPAs with us, other sales by VG Commodities, or contract with us with respect to the sales of our commissioning cargos or the excess capacity covered by the intercompany excess capacity SPAs. Furthermore, any such significant impediment to our customers’ ability or willingness to deliver LNG from the United States generally, or from our projects specifically, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG, and the prospects for international

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natural gas and LNG markets. In particular, changes in the price of natural gas that is supplied to our projects or any other natural gas liquefaction and export facility we may decide to develop in the future could affect the demand for, and price of, the LNG that our projects are expected to produce. Changes in the price of natural gas could also affect the competitiveness of LNG as a source of energy, which could adversely affect our customers or the demand for, and price of, LNG. Any of these factors could, in turn, affect the viability of natural gas liquefaction and export facilities such as those we are proposing to construct, and could require us to re-evaluate the viability of any of our planned projects and result in us postponing or abandoning our current plans for development of our projects. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:

•competitive liquefaction capacity in North America;

•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

•insufficient LNG tanker capacity;

•weather conditions, including temperature volatility resulting from changes in climate, and severe weather events may lead to unexpected distortion in the balance of international LNG supply and demand;

•reduced demand and lower prices for natural gas;

•the extent of domestic production and importation of natural gas in relevant markets;

•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities, which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;

•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;

•changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

•changes in regulatory, tax, environmental or other governmental policies (including tariffs) regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

•political conditions in natural gas producing regions, including geopolitical events such as the Russia-Ukraine conflict and the conflicts occurring in the Middle East;

•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;

•adverse relative demand for LNG compared to other markets, which may decrease LNG exports from North America; and

•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

We may be forced to delay some of our capital projects and our customers, who may be in financial distress, may slow down decision-making, delay planned projects or seek to renegotiate or terminate agreements with us. To the extent any of our counterparties is successful in any such renegotiation or termination, we may not be able to obtain new contract terms that are favorable to us or to replace contracts that are terminated. Counterparties may also be forced to file for bankruptcy protection, in which case our existing contracts with those counterparties may be rejected by the bankruptcy court.

Adverse trends or developments affecting any of these factors above could result in decreases in the price of LNG and/or natural gas, which could adversely affect the LNG business of our customers and the viability of our projects, and could also adversely affect the demand for, and price of, LNG, any of which could have a material

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adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

There may be shortages of LNG tankers worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

The construction and delivery of LNG tankers require significant capital and long construction lead times, and the availability of the tankers (including the tankers that we have contracted to acquire) could be delayed to the detriment of our LNG business and our customers, and therefore our business, because of:

•an inadequate number of shipyards constructing LNG tankers and a backlog of orders at these shipyards;

•political or economic disturbances in the countries where the vessels are being constructed or from where critical equipment is secured;

•acts of war or piracy;

•changes in governmental regulations or maritime self-regulatory organizations;

•work stoppages or other labor disturbances at the shipyards;

•bankruptcy or other financial crisis of shipbuilders or shipowners;

•quality or engineering problems;

•disruptions to maritime transportation routes;

•weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and

•shortages of or delays in the receipt of necessary construction materials.

Delays in the construction and delivery of LNG tankers or other shortages in LNG tankers could result in decreases in the demand for LNG, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Technological innovation may render our anticipated competitive advantage or our processes obsolete.

Our success will depend on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, we are constructing our projects using technologies that we believe provide us with certain advantages (such as the mid-scale natural gas liquefaction trains to be supplied by Baker Hughes). However, we do not have any exclusive rights to any of the technologies that we will be utilizing, and our competitors may be planning to use similar or superior technologies.

In addition, the technologies that we are using or anticipate using in our projects may be rendered obsolete or uneconomical by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others. Our existing contractual arrangements with Baker Hughes would restrict our ability to utilize any such technological advances in our projects. Moreover, any changes to the design of our projects to incorporate any such technological advances could have a negative impact on the applications we have submitted to FERC with respect to those projects. As a result, we may not be able to take advantage of any such technological advances, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Risks Relating to Our Indebtedness and Financing

Our subsidiaries have incurred a significant amount of debt and issued a significant amount of preferred equity, which could adversely affect our financial condition.

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As of December 31, 2025, our subsidiaries had approximately $34.8 billion in outstanding debt, which consisted of $11.1 billion of debt incurred or guaranteed by VGLNG and approximately $23.7 billion in project-level debt financing. As of December 31, 2025, our subsidiaries had approximately $13.5 billion of additional borrowing capacity under our existing financing agreements.

Calcasieu Funding, a subsidiary entity with equity interest in the Calcasieu Project, has issued preferred units for total gross proceeds of $900 million, with an aggregate liquidation preference of approximately $1.7 billion outstanding as of December 31, 2025, some of which require us to make preferential cash distributions to the holders under certain circumstances.

VGLNG also issued 9.000% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share, or the VGLNG Series A Preferred Shares, which are entitled to preferential cash distributions, with an aggregate liquidation preference of $3.0 billion outstanding as of December 31, 2025.

This substantial amount of indebtedness and preferred equity could have important consequences to us, including:

•making it more difficult for us to satisfy our obligations with respect to our existing debt and our subsidiaries’ existing preferred equity;

•limiting our ability, or increasing the costs, to refinance our indebtedness;

•limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy or other purposes;

•limiting our ability to use our cash and capital resources in other areas of our business because we must dedicate a substantial portion of these funds to service debt and preferred equity;

•increasing our vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given our substantial indebtedness that bears interest at variable rates;

•limiting our ability to react to changing market conditions in our industry, to our customers’ businesses and to economic downturns;

•limiting our ability to attract future customers for SPAs in connection with any expansion of our facilities compared with other companies that may have substantially less debt;

•limiting our flexibility in planning for, or reacting to, changes in our business and future business opportunities;

•limiting our ability to capitalize on business opportunities and to react to competitive pressures; and

•resulting in a material adverse effect on our business, operating results and financial condition if we are unable to service our indebtedness or obtain additional capital, as needed.

Under the terms of certain agreements governing our indebtedness, we are permitted to incur additional indebtedness, which could further accentuate these risks.

Servicing our indebtedness and preferred equity will require a significant amount of cash and we may not have sufficient cash, operating cash flows and capital resources to service our existing and future indebtedness and preferred equity.

We may be required to use a substantial portion of our cash and capital resources to pay interest and principal on our indebtedness, as well as cash distributions or other required payments on preferred equity of our subsidiaries. Such payments may reduce the funds available to us to construct and complete the Plaquemines Project, the CP2 Project, or any expansion of our projects or other natural gas liquefaction and export facility we may develop, to acquire our LNG tankers, and for working capital, capital expenditures, and other corporate purposes, and limit our

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ability to obtain additional financing. This may in turn limit our ability to implement our business strategy, heighten our vulnerability to downturns in our business, the industry or in the general economy, and limit our flexibility in planning for, or reacting to, changes in our business and the industry.

We may not have sufficient cash, operating cash flows and capital resources to service our existing and future indebtedness and preferred equity. As of December 31, 2025, our material sales and operating cash flow has been limited to sales of LNG from our Calcasieu Project (including short-term sales of commissioning cargos, sales under our post-COD SPAs, and sales of LNG from excess capacity) and the short-term sales of LNG commissioning cargos from the Plaquemines Project prior to commencing commercial operations. We cannot assure you when we will begin to generate any operating cash flow from commercial operations at the Plaquemines Project, the CP2 Project or any bolt-on expansions thereof or any of our future projects. Our ability to service our debt and preferred equity will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, political, regulatory and other factors, some of which are beyond our control. We also cannot assure you that our business will generate sufficient cash flow from operations or that future financing will be available to us in amounts sufficient to enable us to make required and timely payments on our indebtedness or preferred equity, or to fund our operations.

If we face such liquidity problems, we could be forced to reduce or delay investments and capital expenditures or to dispose of material assets or operations, seek additional debt or equity capital or restructure or refinance our indebtedness or preferred equity. We may not be able to effect any such alternative measures, if necessary, on commercially reasonable terms or at all and, even if successful, those alternative actions may not allow us to make required payments on our indebtedness or preferred equity. In addition, certain agreements governing our existing indebtedness and preferred equity and the terms of such future agreements or preferred equity may also restrict our ability to raise debt or equity capital to be used to repay our existing indebtedness when it becomes due. We may not be able to consummate those dispositions or to obtain proceeds in an amount sufficient to make required payments on our indebtedness or preferred equity when due. If our cash, operating cash flows and capital resources are insufficient to fund those obligations, it could result in an event of default under such indebtedness, which, if not cured or waived, could result in the acceleration of all or a portion of our debt. As a result, our debtholders would be entitled to proceed to foreclose against all collateral that secures such debt, representing substantially all assets of the relevant project. In addition, if the distributions on preferred units issued by Calcasieu Funding are made in the form of an increase in the funding face value instead of in cash for six consecutive calendar quarters with the first full quarter following the commencement of commercial operations of the Calcasieu Project, certain investors may exercise step-in rights to control, directly or indirectly, certain of our subsidiaries and the Calcasieu Project.

As a holding company, the Company depends on the ability of its subsidiaries to transfer funds to it to meet its obligations.

The Company is a holding company for all of our operations and is a legal entity separate from its subsidiaries. As a result, the Company is dependent on the ability of its subsidiaries to make loans, pay dividends and make other payments to generate the funds necessary for the Company to meet its financial obligations and to pay dividends to stockholders, if any. The inability to receive dividends from its subsidiaries could have a material adverse effect on our business, financial condition, cash flows and results of operations. In particular, following COD of the Calcasieu Project, but prior to August 19, 2027, no distributions from Calcasieu Funding to VGLNG, its indirect parent, are permitted until Calcasieu Funding has redeemed in cash any accrued distributions on its preferred units, which are owned by a third party. Furthermore on and after August 19, 2027, no distributions from Calcasieu Funding to VGLNG are permitted until Calcasieu Funding has redeemed in cash all of such preferred units.

The subsidiaries of the Company have no obligation to pay amounts due on any liabilities of the Company or to make funds available to the Company for such payments. The ability of our subsidiaries to pay dividends or other distributions to the Company in the future will depend, among other things, on their earnings, tax considerations and covenants contained in any financing or other agreements, such as the covenants governing our subsidiaries’ current indebtedness and preferred equity. In particular, our subsidiaries may incur additional indebtedness or issue

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additional preferred equity that may restrict or prohibit the making of distributions, the paying of dividends or the making of loans by such subsidiaries to the Company. In addition, such payments may be limited as a result of claims against the Company’s subsidiaries by their creditors, including suppliers, vendors, lessors and employees.

If the ability of the Company’s subsidiaries to pay dividends or make other distributions or payments to the Company is materially restricted by cash needs, bankruptcy or insolvency, or is limited due to operating results or other factors, we may be required to raise cash through the incurrence of debt, the issuance of equity or the sale of assets. However, there is no assurance that we would be able to raise sufficient cash by these means. This could have an adverse effect on the Company’s ability to pay its obligations or pay dividends, if any, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred equity of our subsidiaries also gives the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities or paying dividends to the Company.

Our debt agreements contain various covenants restricting the ability of certain of our subsidiaries to, among other things:

•incur or guarantee additional debt or issue disqualified stock or preferred stock;

•pay dividends (including to the Company) and make other distributions on, or redeem or repurchase, capital stock;

•make certain investments;

•incur certain liens;

•enter into transactions with affiliates;

•merge or consolidate;

•enter into agreements that restrict the ability of restricted subsidiaries to make dividends or other payments to the issuers;

•designate restricted subsidiaries as unrestricted subsidiaries; and

•transfer or sell assets.

In addition, our project financing credit agreements require our projects to maintain certain historical debt service coverage ratios, respective to each project and upon achieving certain milestones.

The holders of Class B common units of Calcasieu Holdings have the right to select and appoint one manager to the board of managers of Calcasieu Holdings, and such manager’s consent is required, among others, prior to:

•amending key project contracts;

•incurring any additional indebtedness in excess of $75.0 million, subject to certain exceptions; and

•issuing or redeeming equity under certain circumstances.

In addition, other than Venture Global Calcasieu Pass Holding, LLC contributing capital in exchange for issuance of common units in Calcasieu Funding, Calcasieu Funding may not issue additional units without a majority approval of holders of its preferred units.

Moreover, the agreements governing the VGLNG Senior Secured Notes and the VGLNG Revolving Credit Facility contain various covenants restricting the ability of certain of our subsidiaries to, among other things:

•incur or guarantee additional indebtedness or issue disqualified stock or certain preferred stock;

•pay dividends and make other distributions or repurchase stock;

•create or incur certain liens;

•merge, consolidate or transfer or sell all or substantially all of their assets; and

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In addition, the terms of the VGLNG Revolving Credit Facility require us to maintain a maximum total leverage ratio of no more than 6.00:1.00.

Our failure to comply with the restrictive covenants described above as well as other terms of our other indebtedness and/or the terms of any future indebtedness from time to time could result in an event of default, which, if not cured or waived, could result in our being required to repay these borrowings before their due date. If we are forced to refinance these borrowings on less favorable terms or are unable to refinance these borrowings, there could be a material adverse effect on our business, financial condition and results of operations.

Additionally, if VGLNG does not pay semi-annual dividends on the VGLNG Series A Preferred Shares, certain terms of the VGLNG Series A Preferred Shares restrict VGLNG’s ability to pay dividends, repurchase its common stock, or issue certain types of securities. Furthermore, when any dividends on any VGLNG Series A Preferred Shares are in arrears for three or more consecutive semi-annual dividend periods, VGLNG is required to increase the number of members of its board of directors by two, until such time as all accrued dividends for all past dividend periods have been fully paid.

As a result of these restrictions, we will be limited as to how we conduct our business and we may be unable to raise additional debt or equity financing to compete effectively, distribute cash from our subsidiaries to the Company, or take advantage of new business opportunities. The terms of any future indebtedness we may incur or equity financing we may raise could include more restrictive covenants. We cannot assure you that we will be able to maintain compliance with these covenants in the future and, if we fail to do so, that we will be able to obtain waivers from the relevant lenders or holders and/or amend these covenants.

Increases in interest rates would increase the cost of servicing our debt and could reduce our profitability.

The debt outstanding under certain of our credit facilities bears interest at variable rates. While a substantial portion of such debt has been hedged to a fixed rate with interest rate swaps, increases in interest rates would increase the cost of servicing our subsidiaries’ debt, even if the amount borrowed remains the same, and could materially reduce our consolidated profitability and cash flows. As a result of such increases in the cost of servicing our subsidiaries’ debt, our subsidiaries may be unable to make distributions to us.

The U.S. Federal Reserve Board significantly increased the federal funds rate in 2022 and 2023, which led to an increase in the borrowing costs on our variable rate debt. While the U.S. Federal Reserve has recently began lowering the federal funds rate (which had a corresponding impact on our borrowing costs), we cannot assure you that the U.S. Federal Reserve will continue to reduce the federal funds rate in the future or whether it will increase such rate. Any future federal funds rate increases could in turn make our financing activities more costly and limit our ability to refinance existing debt when it matures or pay higher interest rates upon refinancing and increase interest expense on refinanced indebtedness. Any federal funds rate increases could in turn make our financing activities more costly and limit our ability to refinance existing debt when it matures or pay higher interest rates upon refinancing and increase interest expense on refinanced indebtedness.

Despite the current level of indebtedness and preferred equity issued by our subsidiaries, we expect to incur significant additional debt, some or all of which may be secured, and equity financing to fund the development, construction and completion of our projects. This could further exacerbate the risks to our financial condition described above.

Although we are subject to certain limitations on additional indebtedness and equity financing pursuant to the terms of agreements governing our existing indebtedness and preferred equity, these restrictions are subject to a number of qualifications and exceptions, and additional indebtedness and/or preferred equity incurred in compliance with these restrictions could be substantial. We expect to incur significant additional debt and equity financing to fund the development, construction and completion of the CP2 Project, any potential bolt-on expansions and any other natural gas liquefaction and export facilities, or other projects, that we may decide to develop in the future. As of December 31, 2025, our subsidiaries had approximately $13.5 billion of additional borrowing capacity in the form of available commitments (all of which would have been secured).

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To the extent we or any of our subsidiaries incurs or issues additional debt and/or preferred equity, as applicable, the risks described in the preceding risk factors would increase.

Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.

If we are unable to fund our debt service obligations or comply with restrictive covenants under our existing or future indebtedness, it could result in an event of default under such indebtedness which, if not cured or waived, could result in the acceleration of some or all of our debt. If we are unable to repay those amounts, our lenders and the holders of our debt securities could proceed to foreclose against the collateral securing such indebtedness. Any such foreclosure could have a material adverse impact on our business, financial condition, cash flows and results of operations.

In particular, we granted holders of the VGLNG Senior Secured Notes and the lenders under the VGLNG Revolving Credit Facility a first-priority lien in substantially all of the existing and future assets of VGLNG, including the direct wholly-owned subsidiaries of VGLNG that directly or indirectly own the Calcasieu Project, the Plaquemines Project, the CP2 Project, any future projects and any related pipeline. Additionally, we granted certain of our lenders under the Calcasieu Pass Credit Facilities and holders of the VGCP Senior Secured Notes: (i) a first-priority perfected security interest in substantially all of VGCP’s and TCP’s existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on all material leasehold and fee interests of VGCP, including, without limitation, the Calcasieu Project site; (iii) a first-priority perfected security interest in 100% of the equity interests in certain subsidiaries relating to the Calcasieu Project; and (iv) all proceeds of the foregoing as collateral. In addition, Calcasieu Pass Pledgor, LLC granted the lenders and holders of the VGCP Senior Secured Notes a first-priority perfected security interest in all of the equity interests in VGCP and TCP. We also granted certain of our lenders under the Plaquemines Credit Facilities and holders of the VGPL Senior Secured Notes: (i) a first-priority perfected security interest in substantially all of Plaquemines’ and Gator Express’ existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on all material leasehold and fee interests of Plaquemines, including, without limitation, the Plaquemines Project site; (iii) 100% of the membership interests in Plaquemines and Gator Express; and (iv) all proceeds of the foregoing as collateral. We granted certain of our lenders under the CP2 Credit Facilities: (i) a first-priority perfected security interest in substantially all of CP2's and CP Express’ existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on all material leasehold and fee interests of CP2, including, without limitation, the CP2 Project site; (iii) 100% of the membership interests in CP2 and CP Express; and (iv) all proceeds of the foregoing as collateral. Further, we granted certain of our lenders under the CP2 EBL Facility (i) a first-priority perfected security interest in substantially all of CP2 Holdings’ existing and after-acquired personal property, including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) 100% of the membership interests in CP2 Holdings; and (iii) all proceeds of the foregoing as collateral. Furthermore, we granted certain of our lenders under the Blackfin Credit Facilities: (i) a first-priority perfected security interest in substantially all of Blackfin Pipeline, LLC's and Blackfin Supply, LLC's existing and after-acquired personal property including, without limitation, proceeds, insurance policies, agreements, permits and bank accounts; (ii) a mortgage on certain material real property interests of Blackfin Pipeline, LLC, and Blackfin, Supply, LLC; (iii) a first-priority perfected security interest in 100% of the equity interests in Blackfin Pipeline, LLC and Blackfin Supply, LLC; and (iv) all proceeds of the foregoing as collateral. As a result, the creditors under any such indebtedness could proceed to foreclose against such collateral securing the applicable indebtedness following an event of default, which would have a material adverse impact on our business, financial condition, cash flows and results of operations.

In addition, the holders of Class B units in Calcasieu Holdings, or the Investors, will have the right to appoint a majority of the board of managers of Calcasieu Holdings, or the Step-In Right, upon the occurrence of certain trigger events. Such trigger events include if an event of default occurs under the Calcasieu Pass Credit Facilities

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and if certain distributions continue to accrue at Calcasieu Funding after COD. Because Calcasieu Holdings is the sole member of the entity that wholly owns the Calcasieu Project and the TransCameron Pipeline, the Step-In Right not only gives the Investors significant control over Calcasieu Holdings but also over the Calcasieu Project and the TransCameron Pipeline. The Investors’ interests may differ from our interests or those of our stockholders, and therefore the Investors may not always exercise the control in a way that benefits us or our stockholders, which may have a negative impact on our business, financial conditions and results of operations.

Our use of hedging arrangements may adversely affect our future operating results or liquidity.

To help mitigate our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we may use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange, or the NYMEX, or over-the-counter options and swaps with other natural gas merchants and financial institutions. Any hedging arrangements would expose us to risk of financial loss in some circumstances, including when:

•expected supply is less than the amount hedged;

•the counterparty to the hedging contract defaults on its contractual obligations; or

•there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other non-U.S. regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

The provisions of the Dodd-Frank Act and the rules adopted and to be adopted by the CFTC, the SEC and other federal regulators establishing federal regulation of the OTC derivatives market, and entities like us that participate in that market, may adversely affect our ability to manage certain of our risks on a cost effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our LNG terminals and to secure natural gas feedstock for our liquefaction facilities.

CFTC position limits rules restrict the amounts of certain speculative futures contracts, as well as economically equivalent options, futures and swaps for or linked to certain physical commodities, including Henry Hub natural gas, that market participants may hold, subject to limited exemptions for certain bona fide hedging positions and other types of transactions. The application of these requirements affect the overall derivatives market, including the costs and availability of the types of swaps we use to hedge or mitigate our commercial risks.

Under the CEA and the rules adopted thereunder, certain swaps may be required to be cleared through a DCO. While the CFTC has designated certain interest rate swaps and index credit default swaps for mandatory clearing, it has not yet adopted rules designating any physical commodity swaps, for mandatory clearing or mandatory exchange trading. Further, we qualify for and rely on the end-user exception from the mandatory clearing and trade execution requirements for any swaps entered into to hedge our commercial risks. If we fail to qualify for that exception as to any swap we enter into and have to clear that swap through a DCO, we could be required to post margin (or post higher margin than if we entered into an uncleared OTC swap) with respect to such swap, our cost of entering into and maintaining such swap could increase, and we would not enjoy the same flexibility with the terms of the cleared swaps that we enjoy with the uncleared OTC swaps we enter into. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as our counterparties, may change the market cost and general availability in the market of swaps of the type we enter into to hedge our commercial risks and, thus, the cost and availability of the swaps that we use for hedging.

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For uncleared swaps, the CFTC and federal banking regulators have adopted rules to require certain market participants to collect and post initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users and certain registered swap dealers and major swap participants. Although we believe we will not be required to post margin with respect to any uncleared swaps we enter into in the future, were we required to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. In addition, some of our counterparties are subject to the regulations imposing capital requirements on them, which may increase the cost to us of entering into swaps with them because, although not required to collect margin from us under the margin rules, our counterparties may contractually require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.

While we are directly subject to only limited regulatory requirements for our derivatives, the application of these requirements to other market participants, including our counterparties, may affect the overall swaps market, including the costs and availability of swaps we may use to hedge or mitigate our risks. If, as a result of the swaps regulatory regime discussed above, we were to reduce our use of swaps to hedge our risks, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

The Federal Reserve Board also has proposed rules that would limit certain physical commodity activities of financial holding companies. Such rules, if adopted, may adversely affect our ability to execute our strategies by restricting our available counterparties for certain types of transactions, limiting our ability to obtain certain services, and reducing liquidity in physical and financial markets. It is uncertain at this time whether, when and in what form the Federal Reserve Board’s proposed rules regarding physical commodity activities of financial holding companies may become final and effective.

European and UK-specific regulations, including but not limited to EMIR, MiFID II, REMIT, MAR, FSMA and the RAO, govern our trading activities and our compliance with such laws may result in increased costs and risks to the business similar to the impacts stated above with respect to the Dodd-Frank Act. The increased costs may also have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Further, any violation of the foregoing laws and regulations could result in investigations, and possible fines and penalties, and in some scenarios, criminal offenses.

Further, the potential for divergence between the UK and EU financial regulatory regimes following the UK’s withdrawal from the EU, has created uncertainty among market participants and may result in additional regulatory risks and compliance costs. While it is expected that the UK will maintain regulatory standards similar to those in the EU, technical differences have emerged recently and it is likely that this trend will continue to increase over time.

We expect that our hedging activities will remain subject to significant and developing regulations and regulatory oversight, and the ultimate effect on our business of any future changes to this regulatory regime remains uncertain.

Risks Relating to Regulation and Litigation

We may fail to receive the required approvals and permits from governmental and regulatory agencies for our projects.

The design, construction and operation of the facilities constituting our projects, as well as the export of LNG and the transportation of natural gas, are highly regulated activities. Certain of our projects remain subject to the application for and/or receipt of several material federal, state and local governmental and regulatory approvals and permits, as described further under Item 1.—Business—Governmental Regulation of this Form 10-K. Approvals of FERC and DOE under Sections 3 and 7 of the Natural Gas Act, or the NGA, as well as several other material governmental and regulatory approvals and permits, including under the Clean Air Act, or the CAA, and the Clean Water Act, or the CWA, are required in order to construct and operate an LNG facility and a natural gas pipeline,

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and to export the LNG produced at our projects. See also Item 1.—Business—Environmental Regulation of this Form 10-K. Our projects that have obtained needed approvals and permits remain subject to extensive regulation.

The authorizations obtained from FERC, DOE and other federal and state regulatory agencies also contain ongoing conditions, and such agencies may impose additional approval and permit requirements. DOE has stated that it has authority to amend, modify, or revoke existing LNG export authorizations issued pursuant to Section 3 of the NGA if necessary or appropriate to protect the public interest. In addition, the DOE may suspend or revoke our export authorizations if we, our customers, and/or their downstream customers, do not comply with the terms and conditions of the authorizations or if the DOE later determines that LNG exports are contrary to the public interest.

On January 20, 2025, President Trump issued an Executive Order entitled “Unleashing American Energy,” that, among other provisions, directed DOE to restart reviews of applications for approvals of LNG exports and directed the consideration of the economic and employment impacts to the U.S. and the impact to the security of allies and partners that would result from granting the application. Other parts of the wide-ranging Executive Order require expedited permitting and elimination of delays and revoke prior executive orders related to the CEQ and greenhouse gas ("GHG") emissions. A second Executive Order issued that same day declared a “National Energy Emergency” and, among other things, recognized the benefits of selling LNG to international allies and partners. On January 21, 2025, DOE directed to the Office of Fossil Energy and Carbon Management to resume consideration of pending applications for LNG exports in accordance with the Natural Gas Act and extended the comment period on the DOE study to March 20, 2025 “to ensure such public interest determinations receive appropriate stakeholder input.” The first Secretarial Order issued by DOE Secretary Wright on February 5, 2025, stated that DOE has resumed consideration of pending export authorizations and will identify and exercise its legal authorities to expedite the approval and construction of reliable energy infrastructure.

On May 19, 2025, DOE issued its response to public comments on the 2024 LNG Export Study, concluding with detailed supporting analysis that LNG exports are consistent with the public interest. Since that date, DOE has issued a series of orders authorizing US LNG exports, including certain orders for our projects. Nevertheless, there can be no assurance as to DOE’s future policies, or the impact of those policies on our existing and future projects, including our related contracts.

While FERC has authorized the siting, construction and operation of the Calcasieu Project, the Plaquemines Project and the CP2 Project, as well as of the related pipelines, under Sections 3 and 7 of the NGA, additional authorizations from the Commission and/or staff of FERC, as applicable, are still needed as part of FERC’s ongoing regulation of our projects. Such implementation authorizations are required to complete the construction and commissioning of the Plaquemines Project and place its facilities into commercial service, and similar authorizations will be needed throughout the construction and commissioning of the CP2 Project.

We have other planned projects that have not yet received required authorizations from FERC or DOE. We have recently filed for, but not yet obtained, authorizations for certain projects such as Plaquemines Expansion Project and our requests to increase the authorized output of the existing Plaquemines Project and the CP2 Project without adding any new facilities. We have not yet made any filings to the FERC or DOE regarding any other future project or any expansions. As we proceed with our efforts to obtain regulatory approvals for such projects, we may face additional regulatory risks or delays from time to time as they are based on various factors outside of our control. There can be no assurance that regulatory risks or issues from FERC or other regulatory agencies will not interfere with our prevent our plans to develop these additional projects.

We cannot predict whether our applications, approvals or permits will attract significant opposition or whether the permitting process will be lengthened due to complexities and appeals, including uncertainty and delays in the timetable on which the DOE will authorize increases in the expected annualized peak liquefaction capacity for the Plaquemines Project and exports from, the Plaquemines Expansion Project, as well as for the FERC and DOE to act on future applications for our other future projects or expansions, litigation by environmental groups and other advocates concerned about the impact of our projects on climate change and pollution as well as resistance by local communities due to environmental, health and safety concerns. A number of environmental groups have actively

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opposed the regulatory approvals necessary for our projects, including by pursuing appeals of authorizations we have received for the CP2 Project. See —Risks Relating to Our Project and Other Assets—Various economic and political factors, including opposition by environmental or other public interest groups, could negatively affect the timing or overall development, construction and operation of our projects, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Opposition to our projects from environmental groups and other advocates may increase and strengthen over time. Any appeal of or litigation relating to our permits or approvals may delay the development of our natural gas liquefaction and export facilities. There can be no assurance that any opposition, appeals or other litigation, will not be successful or not delay our ability to develop the CP2 Project, or any other future projects or expansions we may seek to develop.

We do not know whether or when any of the approvals or permits we require can be obtained, whether any existing or potential future interventions or other actions by third parties will interfere with our ability to obtain and maintain such approvals or permits, whether any such approvals and permits may be revoked or altered in the future, or whether we will be able to comply with the conditions or requirements that such approvals or permits might impose. In addition, requests by regulators for additional information or additional regulatory submissions may delay the regulatory approval process and may also lead to changes in our project design. There is no assurance that we will obtain and maintain these governmental approvals and permits, or that we will be able to obtain them on a timely basis.

The denial of an application, approval or permit essential to a project or bolt-on expansion opportunity or the imposition of impractical conditions would impair our ability to develop a project or bolt-on expansion opportunity. Similarly, a delay in the review and permitting process for our projects or bolt-on expansion opportunities could impair or delay our ability to develop the relevant project or bolt-on expansion opportunity or increase the cost so substantially that the relevant project or bolt-on expansion opportunity is no longer financially attractive to us. Certain of the foregoing approvals and permits must be obtained before construction of a particular project or bolt-on opportunity can begin, and before we can pursue any additional potential bolt-on expansion opportunities at such projects. If we are unable to obtain and maintain the necessary approvals and permits or satisfy additional permit requirements imposed on us, we may not be able to complete our projects on schedule or operate them and provide services to our customers under the SPAs and, consequently, a failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

In the future, additional regulatory approvals may be required or significant costs may be incurred due to delays caused by the opposition, changes in laws and regulations or for other reasons. In addition, zoning, environmental, health and safety laws and regulations are subject to periodic amendment or promulgation and may become more stringent over time. Accordingly, we cannot assure that such laws or regulations will not be changed or reinterpreted or that new laws or regulations will not be adopted. The costs of complying with future laws and regulations may require us to incur materially higher costs.

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Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation.

Our natural gas pipelines providing interstate transportation are subject to regulation by FERC under the NGA and under the Natural Gas Policy Act of 1978, or the NGPA. FERC regulates the transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. If our interstate natural gas pipelines fail to comply with all applicable statutes, rules, regulations and orders, they could be subject to substantial penalties and fines.

As our interstate natural gas pipelines are subject to FERC regulations, we must file FERC gas tariffs, as well as any subsequent changes to the filed FERC gas tariffs or agreements related to the pipelines from time to time, with FERC for approval for each of our pipelines. We have currently effective tariffs in place for our TransCameron and Gator Express pipelines, and any changes to those tariffs would require FERC approval. The construction and operation of any new, modified, or expanded facilities on our pipelines may also require FERC authorization. There can be no assurance that FERC will accept such filings on anticipated terms and timelines, or at all.

Should we, or any of our applicable subsidiaries that own a FERC-jurisdictional pipeline fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we or such subsidiary could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct, FERC has civil penalty authority under the NGA and the NGPA to impose penalties for violations of currently up to approximately $1.58 million (with future changes indexed to inflation) per day for each violation.

Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.

The Pipeline and Hazardous Materials Safety Administration, or PHMSA, has exclusive authority to establish and enforce safety regulations for onshore LNG facilities and pipelines transporting hazardous materials such as natural gas. PHMSA periodically inspects LNG facilities and operators to enforce compliance with the applicable safety regulations. During the inspections, PHMSA reviews operator records to determine if facility equipment has been properly maintained and if the operator has developed and follows operation, maintenance, security, and emergency procedures that ensure the continued safe operation of the facility. Compliance with PHMSA requirements, which may change over time, can impose additional costs or liabilities on us or adversely affect our operations. PHMSA enforces violations it finds, which can include civil penalties or orders directing action. In addition, if PHMSA finds conditions that are hazardous, it can require the shut-down of the relevant facilities and expeditious corrections of the conditions through corrective action orders.

PHMSA also requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:

•perform ongoing assessments of pipeline integrity;

•identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”;

•improve data collection, integrate and analyze pipeline data;

•repair and remediate the pipeline as necessary; and

•implement preventative and mitigating actions.

We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. PHMSA has authority to impose administrative fines and penalties for violations of its safety standards, and such violations may also give rise to civil enforcement actions.

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In addition, the costs of compliance with integrity management programs and other PHMSA requirements may be difficult to predict. Furthermore, these standards are subject to regular statutory and regulatory revision and generally have become more stringent over time, as PHMSA promulgates new or revised regulations and as Congress amends existing pipeline safety laws. If these standards become more stringent in the future, it could cause us, like other similarly situated pipeline operators, to incur increased costs for operating our pipelines, to incur increased costs for developing future projects or bolt-on expansion opportunities, or to suffer potential adverse impacts to our operations. For instance, on January 17, 2025, PHMSA issued a final rulemaking implementing a mandate under the Protecting Our Infrastructure and Enhancing Safety Act of 2020, or the PIPES Act, to reduce methane emissions from new and existing natural gas transmission, regulated gathering and distribution pipelines, natural gas storage, and LNG facilities. The rule imposes enhanced leak survey and patrolling requirements, standards for leak detection programs, leak grading and repair criteria, repair timelines, requirements for mitigation of emissions from blowdowns, requirements for investigating failures, and criteria for the design, configuration and maintenance of pressure relief devices. However, the rule was not published in the Federal Register prior to a regulatory freeze issued by the Trump administration on January 20, 2025 and therefore has not taken effect. Any future rule implementing these mandates under PIPES Act may require operators of pipelines and facilities to make operational changes or modifications at their facilities to meet standards beyond current requirements. In May 2025, PHMSA issued two Advance Notices of Proposed Rulemaking (“ANPRM”) seeking public comment on updates to its safety regulations for pipelines and LNG facilities aimed at implementing the President’s “Unleashing American Energy” Executive Order. In June 2025, PHMSA issued another ANPRM to solicit stakeholder feedback on whether to repeal or amend any requirements in its pipeline safety regulations to eliminate undue burdens on the identification, development, and use of domestic energy resources and to improve government efficiency. The ultimate impact of those efforts of the Trump Administration remains to be seen. If safety standards were to become more stringent in the future, it could cause us, like other similarly situated companies, to make changes or modifications at our facilities that may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

Any repair, remediation or delayed remediation, preventative or mitigating actions may require significant capital and operating expenditures and may subject us to significant reputational or financial risk. Should we fail to comply with applicable statutes and the PHMSA rules and related regulations and orders, we could be subject to significant penalties and fines, which would have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Existing and future environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating and/or construction costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws and regulations that regulate and restrict, among other things, discharges to air, land and water, with particular respect to the protection of the environment and natural resources; the handling, storage and disposal of hazardous materials, hazardous waste, and petroleum products; and investigation and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, Oil Pollution Act, or OPA, CWA, Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and Resource Conservation and Recovery Act, or RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our projects and any other natural gas liquefaction and export facility we may decide to develop in the future, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and to provide reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our projects and related pipelines, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, operational or construction restrictions, difficulty obtaining and maintaining permits from regulatory agencies or capital expenditures and operational costs related to pollution control equipment that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

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Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of the proposed liquefaction facilities, we could be liable for the costs of investigating and cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources, including as they relate to releases of hazardous substances that pre-date our possession and operation.

We have conducted Phase I environmental studies on all of our project sites, and from time to time we have encountered environmental conditions on certain sites that we may be required to monitor or address prior to making use of the relevant project site. In addition, future studies and analyses may reveal adverse environmental conditions on them of which we are not currently aware, and we may be required to investigate and remediate such conditions or make other changes to those sites. Any discovery of preexisting, or occurrence of new, environmental conditions that require remediation or other alterations to our current plans for our projects could delay or prevent the construction of that project, or require us to pay penalties or fines or otherwise incur significant losses and liabilities, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Federal and state regulatory authorities have pursued regulatory and policy initiatives to reduce GHG emissions in the United States from a variety of sources, but such initiatives continue to be controversial and subject to frequent changes and revisions depending on legal and political developments. For example, on December 15, 2009, the Environmental Protection Agency, or the EPA, published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment, which provided legal support for EPA to pursue GHG emissions regulations under the Clean Air Act. However, on August 1, 2025, the EPA issued a proposed rule that would rescind these findings. In addition, in May 2024, the EPA finalized a new rule regulating GHG emissions from the power sector that would phase in requirements for certain fossil fuel-fired power plants to implement GHG reduction methods, including, among other things, the installation of systems to capture and sequester their carbon emissions. This rule is the subject of legal challenges pending before the Court of Appeals for the District of Columbia, as well as, a June 2025 EPA proposal that would repeal it. We cannot predict the outcome of these developments.

On December 2, 2023, EPA issued a final rule updating and broadening requirements for new, modified, and reconstructed oil and gas sources, including oil and gas wells, controllers, pumps, storage vessels, and compressor stations aimed at reducing methane and volatile organic compound emissions and directing states to develop plans largely paralleling these requirements for hundreds of thousands of existing oil and gas sources. The rule also includes a Super-Emitter Response Program, whereby qualified third parties may document super-emitter events and notify owners or operators of affected sites, requiring them to investigate and take measures to mitigate methane emissions. This rule is subject to pending legal challenges in the Court of Appeals for the District of Columbia as well. On January 20, 2025, President Trump signed an Executive Order to once again withdraw the U.S. from the Paris Agreement as well as a wide-ranging Executive Order entitled “Unleashing American Energy,” that, among other provisions, directed all agencies to adhere to only relevant legislated requirements for environmental considerations and to prioritize energy production. The future impact of these actions, and the current U.S. administration generally, on GHG emissions and climate-related regulations and initiatives cannot be predicted at this time.

Section 60113 of the Inflation Reduction Act, which was signed into law on August 16, 2022, establishes a charge on excess methane emissions from various facilities operating in the oil and gas sector, including liquefied natural gas storage and liquefied natural gas import and export equipment, that report more than 25,000 metric tons of carbon dioxide equivalent emissions per year. For liquefied natural gas facilities, the excess emissions charge is based on the reported tons of methane emissions that exceed 0.05 percent of the natural gas sent to sale from or through such facilities. We anticipate that our facilities would be subject to such excess emissions charge. In March 2025, President Trump signed a measure passed by Congress to repeal the EPA rule implementing the emissions charge. On July 4, 2025, President Trump signed the One Big Beautiful Bill Act, which, among other things, postpones the EPA’s imposition of the emissions charge until 2034. The future prospects of the emissions charge remain uncertain.

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The United States Congress has from time to time considered other legislation to restrict or regulate emissions of GHGs. The United States Congress has from time to time considered other legislation to restrict or regulate emissions of GHGs, including energy legislation or other initiatives that seek to address GHG emissions issues or restrict oil and gas operations. In addition to the uncertainties in federal climate policy, we could still be subject to or impacted by international initiatives, state initiatives or by future federal regulatory initiatives, which could include direct GHG emissions regulations, a carbon emissions tax, or cap-and-trade programs. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

Other federal and state initiatives, as well as initiatives in foreign jurisdictions where we intend to market our products, have been implemented, are being considered or may be considered in the future to address GHG emissions and other climate and environmental concerns. These may include, but are not limited to, treaty commitments, direct regulation, carbon emissions taxes, cap and trade programs or mandates to the power sector to incorporate certain percentages of renewable energy into their portfolio. For example, the EU has adopted a legally binding target of net zero GHG emissions by 2050. Additionally, in August 2024, an EU regulation went into effect that is aimed at reducing methane emissions associated with natural gas, oil and coal imports and imposes monitoring, reporting and verification standards on importers of fossil fuels into the EU with respect to the “life cycle” methane emissions associated with the products. Certain initial reporting requirements commenced in 2025, and reporting requirements for importers to demonstrate that imports were produced in accordance with monitoring, reporting and verification standards equivalent to EU requirements will take effect in 2027. EU authorities are in the process of developing rules for importers to demonstrate equivalency under the regulation. In addition, the U.S. administration has been lobbying the EU to exempt U.S. companies from the regulation until 2035. The ultimate scope of this regulation, including the outcome of lobbying efforts for U.S. exemptions, and the impact on our compliance, reporting and operational costs, and the marketability of our imports, remains uncertain.

In addition, from time to time, proposals have been made to change the way FERC considers GHG emissions in reviewing applications under the National Environmental Policy Act, or NEPA, and the NGA. For example, in January 2025, FERC withdrew its draft interim policy statement for consideration of GHG emissions in natural gas infrastructure reviews, stating that impacts associated with GHG emissions would be considered on a case-by-case basis. In May 2024, the CEQ published final “Phase 2” NEPA regulations which included specific direction to account for both climate change and environmental justice effects in NEPA reviews. However, these regulations were ultimately rescinded by CEQ in 2025. In May 2025, CEQ also withdraw previous interim guidance intended to assist agencies in their consideration of the effects of GHG emissions and climate change in NEPA review. While the ultimate scope and content of GHG emissions and climate-related analysis in NEPA reviews remains uncertain, any future initiatives or proposals to include such considerations could affect the demand for, or the availability or cost of, natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

GHG emissions (such as carbon dioxide and methane) that could be regulated include, among others, those associated with our power generation, liquefaction and transportation of natural gas, and consumers’ or customers’ use of our products. Many of these activities, such as consumers’ and customers’ use of our products, as well as actions taken by our competitors in response to such laws and regulations, are beyond our control. Attention to climate change risks has also resulted and may continue to result in private initiatives by certain members of the investment community as well as public interest groups aimed at discouraging the production, development and consumption of fossil fuels.

GHG emissions-related laws and related regulations, consumer and investor preferences with respect to fossil fuels and the effects of operating in a potentially carbon-constrained environment may result in substantially increased capital, compliance, operating and maintenance costs and could, among other things, reduce demand for LNG, make our products more expensive and adversely affect our sales volumes, revenues and margins.

The ultimate effect of international agreements and national, regional and state legislation and regulatory measures to limit GHG emissions on our financial performance, and the timing of these effects, will depend on numerous factors. Such factors include, among others, the sectors covered, the GHG emissions reductions required

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and the extent to which we are able to recover the costs incurred through the pricing of our products in the competitive marketplace. Further, the ultimate impact of GHG emissions-related agreements, legislation, regulations, or private initiatives on our financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes and the timing thereof.

Other future legislation and regulations, such as those relating to the transportation and security of LNG exported from our projects, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We are involved, and may in the future become involved, in disputes and legal proceedings.

We are involved, and may in the future become involved, in disputes as well as legal proceedings with public authorities, shareholders, suppliers, contractors, customers, land-owners, current or former employees, and others. Given the nature of our business, such disputes and legal proceedings often involve highly complex legal and factual questions and determinations and, in some cases, introduce significant levels of exposure.

For example, the Calcasieu Project is currently involved in arbitration proceedings with certain of its customers under post-COD SPAs related to the Calcasieu Project as described in more detail under Item 3.—Legal Proceedings. Additionally, see —If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.

In addition, between 2023 and 2025 certain of our former employees filed proceedings, including in Virginia federal court, with respect to alleged breaches of certain stock option grant agreements and related matters. See Item Item 3.—Legal Proceedings for additional information. While most of these proceedings have been resolved, certain of these proceedings remain pending. We disagree with the assertions in each of these proceedings and are defending ourselves and asserting counterclaims, where applicable. There can be no assurance that we will be successful in defending any remaining claims.

Further, a putative securities class action complaint naming Venture Global, our directors and certain of our officers and our underwriters, as well as Venture Global Partners II, LLC, was filed in April 2025 and subsequently amended in September and December 2025. The complaint asserts claims under Sections 11, 12, and 15 of the Securities Act on behalf of a putative class of all persons and entities who purchased or otherwise acquired our Class A common stock pursuant and/or traceable to the registration statement for the IPO and contends that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedly false or misleading and seeks unspecified damages on behalf of the putative class. Further, four putative shareholder derivative action complaints naming Venture Global, our directors, certain of our officers and certain of our underwriters have been filed contending that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedly false or misleading. The complaint asserts breaches of fiduciary duties, gross mismanagement, waste of corporate assets, unjust enrichment, and aiding and abetting, and seeks unspecified damages for such breaches. All four shareholder derivative action complaints have been stayed pending resolution of our motion to dismiss the amended securities class action complaint that we filed on January 28, 2026. See Item 3.—Legal Proceedings for additional information. The Company believes all of the foregoing claims are without merit and intends to defend itself vigorously.

In addition to these specific disputes, we are and have been involved, and may in the future become involved, in various administrative, regulatory or other legal proceedings, and others have alleged and may in the future allege

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that we are in violation or in default under orders, statutes, rules or regulations relating to the environment, employment law, compliance plans imposed or agreed to by us, or permits issued by various local, state or federal agencies for the construction or operation of our natural gas liquefaction facilities. We have been and may in the future also be subject to claims for personal injury, or property damage, in connection with the construction or operation of our natural gas liquefaction facilities.

Assessment of potential outcomes and the potential damages and other losses we may incur arising out of any current or future disputes or legal proceedings is inherently difficult given, among other things, the complex nature of the facts and law involved. Although we may disagree with any assertions and claims made against us in any such disputes or legal proceedings, we may not be successful in defending against such claims. If legal proceedings are resolved against us or if we make out-of-court settlements, we may be obliged to make substantial payments to other parties. While we maintain liability and other insurance policies, such insurance may be limited and have exclusions that leave us exposed to costs associated with disputes and legal proceedings. Even if we are ultimately successful in the legal proceedings, such proceedings may distract our management team and we may also face harm to our reputation from case-related publicity. Further, any such disputes or legal proceedings could result in substantial costs to us associated with defending such claims and distract management, could have a material adverse effect on our reputation, and could also impact our ability to complete our projects and any natural gas liquefaction and export facility we may decide to develop in the future on their respective anticipated timelines and at their respective anticipated costs.

If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.

We are involved, and may in the future become involved, in disputes and arbitration proceedings with the customers under our SPAs as described in more detail under Item 3.—Legal Proceedings. Certain of such claims have been denied or settled, but a number of such claims remain ongoing and in one instance the customer whose claim was denied in arbitration has filed a petition with the New York Supreme Court seeking to vacate the applicable arbitral award.

We disagree with the assertions and legal claims in each of the ongoing requests for arbitration and the legal proceedings seeking to vacate one such arbitral award, and the Calcasieu Project is vigorously defending the remaining arbitration proceedings and such legal proceedings. While we believe that any damages award in such arbitration proceedings should be subject to the relevant seller aggregate liability cap under the relevant post-COD SPA (other than in in the case of the arbitration award relating to the BP post-COD SPA), there can be no assurance that the Calcasieu Project will be successful in defending such ongoing claims or establishing that any such claim is subject to the applicable liability cap. In addition, although none of the post-COD SPA customers who have commenced the arbitration proceedings described above has sought termination of the underlying post-COD SPA as a remedy in the relevant arbitration, two of those long-term post-COD SPA customers have notified the collateral agent for the Calcasieu Project’s project financing that a potential termination event under their long-term post-COD SPA has occurred or may occur, and that remedies could include termination of, or suspension under, the relevant long-term post-COD SPA.

If the Calcasieu Project is unsuccessful in defending against any of these ongoing claims, the amounts it could be required to pay could be substantial, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects, and contribute to increased volatility in the value of our Class A Common Stock. Further, a termination of, or suspension under, any of the relevant long-term post-COD SPAs that are subject to these claims could, subject to our ability to replace such long-term post-COD SPAs during the applicable grace period, lead to an acceleration of our outstanding debt under the Calcasieu Project and foreclosure against all collateral that secures such debt, representing substantially all assets of the Calcasieu Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

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If certain customers were to successfully terminate their post-COD SPAs for the Calcasieu Project, we would need to replace those customers and/or amend the Calcasieu Project's existing post-COD SPAs over a certain period of time that may extend up to 180 days, which could take time and there can be no assurance we would be able to enter into new post-COD SPAs on a timely basis and on comparable or better terms. See —Risks Relating to Our Business—Our customers or we may terminate our SPAs if certain conditions are not met or for other reasons. See also —Risks Relating to Our Indebtedness and Financing—Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.

Risks Relating to Our Projects and Other Assets

We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs.

We are in the process of constructing and commissioning the Plaquemines Project, developing and constructing the CP2 Project and developing certain of our other future projects and expansions, including the CP2 Expansion Project and the Plaquemines Expansion Project. While we believe we have sufficient cash and access to substantial commissioning cargo proceeds to fund the completion of the Plaquemines Project and the construction and commissioning of Phase 1 of the CP2 Project based on our current estimate of the Total Project Costs, the development, construction and financing of Phase 2 of the CP2 Project, as well as our other current and future projects and expansions, will require significant additional funding.

We currently estimate that approximately $0.6 billion to $1.0 billion of the Total Project Cost for the Plaquemines Project, has yet to be paid as of December 31, 2025. In addition, as of December 31, 2025, we estimate that the Total Project Cost for the first and second phases of CP2 Project will range from approximately $32.5 billion to $33.5 billion, including EPC contractor profit and contingency, owners’ costs and financing costs, of which $9.9 billion had been paid for as of December 31, 2025. These estimates are based primarily upon our construction cost experiences with the Calcasieu Project and the Plaquemines Project and the pricing included in the CP2 EPC Contracts. They also reflect the current inflationary environment, the potential impact of tariffs in place as of December 31, 2025, as well as the fact that the pipeline for the CP2 Project is expected to be longer and more expensive than the pipelines for the Calcasieu Project and the Plaquemines Project. Our actual costs could vary significantly from our preliminary estimates. Further, these cost estimates do not include the cost of the Plaquemines Expansion Project or the CP2 Expansion Project, nor do they reflect the potential impact of any new tariffs that have been announced or implemented after December 31, 2025 or that may be implemented in the future. Our Total Project Cost estimates included in this Form 10-K reflect all tariffs in place, and Section 232 exemptions secured, as of December 31, 2025, but do not reflect the potential impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on our Total Project Cost estimates. Certain of our key components, including our Baker Hughes sourced liquefaction train system modules and power island components, are foreign sourced and specified under our regulatory approvals, offering no domestically sourced alternative and potentially exposing us to the effects of any future tariffs that may be imposed. There can be no assurance as to the extent of any future tariffs, or the impact thereof on any of our estimates of Total Project Costs for our projects, which could have a material adverse effect on our construction budgets and limit our growth prospects.

Moreover, no substantial construction work has been undertaken on any of our other future projects or expansions to date, and we have not yet entered into a number of material contracts (including EPC contracts) for such other future projects or expansions, and our actual costs could vary significantly from the costs of our other projects depending on the terms we may agree to for those contracts. There is no guarantee that we will be able to enter into the necessary contracts to construct any other future projects or expansions on the same or substantially similar terms as the Calcasieu EPC Contract, the Plaquemines EPC Contracts or the CP2 EPC Contracts. As a

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result, our cost estimates are only an approximation of the actual costs of construction and financing for such projects.

Our actual project costs may be higher, potentially materially, compared to our current estimates as a result of many factors which could result in the need to contribute additional equity into our projects. See further discussion under —Our estimated costs for our projects have been, and continue to be, subject to change due to various factors. For example, our cost estimates might change due to factors such as unexpected delays in the construction or commissioning of our projects, the execution of any repair or warranty work and change orders or amendments to certain material construction contracts, including final terms of or amendments to any EPC contract for such projects, and/or other construction or supply contracts. Accordingly, we will need to obtain significant additional funding from one or more sources of debt and equity financing before we are able to generate sales and/or revenue for our projects, other than the Calcasieu Project, the Plaquemines Project, and Phase 1 of the CP2 Project.

The amount of project-level equity funding that is required for any of our projects relative to the amount of project-level debt financing may differ between our projects. Generally, we expect to finance approximately 50% to 75% of the anticipated project costs of each of our projects with project-level debt financing (which may include limited recourse debt), and the remaining 25% to 50% with project-level equity (which may consist of equity contributions by us, equity contributed by others, equity financing transactions, mezzanine financing and/or other similar financing alternatives), or cash generated by the relevant project. However, the proportion of project-level debt to equity funding will depend on various factors, including market conditions and the amount of long-term contracted revenues for the relevant project. As a result, there can be no assurance as to the ultimate amount of project-level debt financing that will be available to us for a particular project on acceptable terms, which could have an adverse impact on our ability to finance the relevant project and may require us to raise additional debt, equity or equity-linked financing above relevant project entities, including potentially at the Company level, through additional debt, equity or equity-linked financing. We do not currently have any committed project-level debt or equity financing for Phase 2 of the CP2 Project or any other future projects or expansions. We may consider alternative structures to raise capital for those projects and, as a result, there can be no assurance that the financing structure for Phase 2 of the CP2 Project, or any other future project or expansions we may develop will be similar to those used for the Calcasieu Project, the Plaquemines Project or Phase 1 of the CP2 Project.

Additional capital may not be available in the amounts required, on favorable terms, or at all. In addition, if any adverse findings are discovered at any stage during the course of our development of our projects that would render part of, or all of, any such sites to be unsuitable or we discover flaws that may decrease the value of such sites as collateral for purposes of any financing, then we may not be able to obtain the financing necessary to construct the relevant project on favorable terms, or at all. For example, such adverse findings may include the discovery of environmental conditions on the relevant project site that require investigation, remediation or other changes to the relevant project that make it more difficult for us to obtain the necessary regulatory approvals.

Furthermore, any adverse changes in natural gas demand that affect the competitiveness of LNG or any failure on our part to obtain or comply with necessary permits or approvals may also hinder our ability to obtain necessary additional capital or financing.

Delays in the construction of our projects beyond the estimated development period, issues with the commissioning process leading to additional repair and replacement work, as well as change orders to certain material construction contracts and/or other construction or supply contracts, could increase the cost of completion beyond the amounts that we estimate and beyond the then-available proceeds from sales of commissioning cargos we expect to receive, which could require us to obtain additional sources of financing to fund our operations until our projects are fully completed (which could cause further delays). For example, we experienced unexpected delays in commissioning the Calcasieu Project related to certain necessary repairs and replacements. As a result, COD for the Calcasieu Project did not occur until April 15, 2025 due to significant work related to commissioning, carryover completions, rectification, and certain other items. Further, while we generated commissioning cargo proceeds at the Calcasieu Project prior to achieving COD and are currently generating commissioning cargo proceeds at the Plaquemines Project, and we plan to sell commissioning cargos at each of our other projects, it is possible those commissioning cargo proceeds will be lower, potentially materially, than we currently anticipate,

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which could also require us to obtain additional sources of capital to fund development, construction and commissioning of our projects.

Our future liquidity may also be affected by the timing and availability of financing in relation to the incurrence of construction costs for our projects and other outflows and by the timing of receipt of cash flow under the SPAs in relation to the incurrence of various project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between liquidity sources and cash needs, including factors such as construction delays and breaches of agreements.

Our ability to obtain financing that may be needed to provide additional funding will depend, in part, on factors beyond our control and there can be no assurances that funding will be available to us on acceptable commercial terms or at all. For example, capital providers or their applicable regulators may elect to cease funding LNG projects or certain related businesses. Accordingly, we may not be able to obtain financing on terms that are acceptable to us, or at all. Even if we are able to obtain financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our business plan and the viability of the relevant project. The failure to obtain any necessary additional funding could cause any or all of our projects to be delayed or not be completed. Any delays in construction could prevent us from commencing operations when we anticipate and could prevent us from realizing anticipated cash flows, all of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We may not construct or operate all of our proposed LNG facilities or pipelines or any additional LNG facilities or pipelines beyond those currently planned, and we may not pursue some or any of the bolt-on expansion opportunities we have identified at our current projects, which could limit our growth prospects.

We may not construct some of our proposed LNG facilities or pipelines, and we may not pursue some or any of the bolt-on expansion opportunities we have identified at our current projects, in each case whether due to lack of commercial interest, inability to obtain financing, inability to obtain adequate supply of materials and equipment to complete construction of our projects, inability to obtain necessary regulatory approvals (including as a result of political factors, environmental concerns or public opposition) or otherwise. For example, we previously decided to withdraw the Delta Project from the FERC pre-filing process and replace the Delta Project with the proposed Plaquemines Expansion Project. Our ability to develop additional liquefaction facilities or to pursue bolt-on expansion opportunities at our projects will also depend on the availability and pricing of LNG and natural gas in North America and other places around the world regulatory approvals, and other factors. If we are unable or unwilling to construct and operate additional LNG facilities or bolt-on expansion opportunities at our current projects, our prospects for growth will be limited.

Our natural gas liquefaction and export projects face, and our future projects or expansions may face, significant operational risks.

As more fully discussed in these —Risk Factors, our existing and future projects, and expansions thereof, involve operational risks, including the following:

•explosions, pollution, releases of toxic substances;

•the facilities performing below expected levels of efficiency;

•breakdown or failures of equipment;

•unanticipated changes in domestic and international market demand for and supply of natural gas and LNG, which will depend in part on supplies of and prices for alternative energy sources and the discovery of new sources of natural resources;

•operational errors by vessel or tug operators;

•operational errors by us or any contracted facility operator;

•labor disputes; and

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•weather-related interruptions of operations, natural disasters, fires, floods, accidents or other catastrophes.

If any of such operational risks materializes, it could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We have multiple procurement and construction contracts. Failure by one contractor to perform under its applicable material procurement and/or construction contract could lead to failure to perform or delay in performance by others under their construction contracts.

Our strategy for each project involves us entering into and administering a number of procurement and construction contracts, which differs from certain other LNG projects of this scale developed in the United States.

Failure of any of the counterparties to these procurement and/or construction contracts to complete its contractual obligations on a timely basis could result in material delays in the ability of our projects to achieve commercial operation. In addition, any such failure by any of the foregoing counterparties could affect the schedule of other construction contractors and/or require change orders to multiple material construction contracts. Although the scope of each such contractor is defined in the applicable material contract to which it is a party, in the event of delays or other procurement or construction issues, each such contractor may seek to shift responsibility for delays or other issues to other contractors, resulting in increased costs or delays.

We are dependent on our contractors for the successful completion of our projects and any bolt-on expansion opportunities at our projects that we may pursue, and any failure by our contractors to perform their contractual obligations could have a material adverse impact on our projects.

There is limited recent industry experience in the United States regarding the construction or operation of mid-scale natural gas liquefaction and export facilities. Timely and cost-effective completion of our projects or any bolt-on expansion opportunities at our projects in compliance with agreed upon specifications is highly dependent upon the performance of our contractors pursuant to their agreements with us. Moreover, our construction strategy involves multiple construction contracts, which differs from certain other LNG projects of this scale developed in the United States. Failure by one contractor to perform under its applicable material construction contract could lead to failure to perform or delay in performance by others under their construction contracts.

Successful construction and operation of our projects, or any bolt-on expansions at our projects, will depend on the adequacy and timeliness of performance of our contractors. The failure of our contractors to perform as expected could have a material adverse impact on our ability to complete our projects, or any bolt-on expansions at our projects, on our anticipated schedule and budget, or at all. Further, if the completion and the commercial operation date of the Plaquemines Project or the CP2 Project are delayed beyond an agreed date certain for each project, an event of default under the Plaquemines Credit Facilities, the VGPL Senior Secured Notes, the CP2 Credit Facilities or the CP2 EBL Facility, may occur. See —Risks Relating to Our Indebtedness and Financing—Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.

Further, our ability to complete our projects, or any bolt-on expansions at our projects, and commence operations at each of our projects, or any bolt-on expansions at our projects, depends on completion of construction of our projects, or any bolt-on expansions at our projects, in accordance with our design and quality standards. Faulty construction that does not conform to those standards could have a material impact on our ability to complete our projects, or any bolt-on expansions at our projects, on our anticipated schedule, and could also have material adverse effects on the operation of the facilities (for example, improper equipment installation may lead to a shortened life of our equipment, increased operations and maintenance costs or a reduced availability or production capacity of the affected facility).

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Timely and cost-effective completion of the projects, or any bolt-on expansions at our projects, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance by the construction contractors of their obligations under the material construction contracts. The ability of our current or intended contractors to complete our projects in accordance with our design and quality standards and on our anticipated schedule is dependent on a number of factors, including such construction contractor’s ability to, as applicable:

•maintain its own financial condition, including adequate working capital, and its ability to pay debt service and other liabilities;

•accurately estimate certain costs, including material, construction and fabrication costs, from third parties such as suppliers and subcontractors;

•respond to difficulties such as equipment failure, increased costs, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;

•design, engineer and build the facilities constituting the projects to operate in accordance with specifications and on schedule;

•engage and retain third-party subcontractors and procure equipment and supplies;

•attract, develop and retain skilled personnel, including engineers, and address any labor issues that may arise;

•respond to market conditions in the construction industry, including recent shortages of personnel and recent increases in operating costs;

•address any start-up and operational issues that may arise in connection with the commencement of commercial operations;

•post and maintain required construction bonds or other performance assurance and comply with the terms thereof; and

•manage the construction process generally, including coordinating with other contractors, third-party contractors and regulatory agencies.

Although agreements with our contractors may provide for liquidated damages if the relevant contractor fails to perform its obligations under the applicable agreement, such failure may delay or permanently impair the operations of our projects, or any bolt-on expansions at our projects. Moreover, any liquidated damages that we may be entitled to receive may be subject to certain liability caps, and may not be sufficient to cover the damages that we suffer, or that we may be required to pay to our customers or our lenders as a result of any such delay or impairment. Furthermore, we may have disagreements with our current or intended contractors about different elements of the construction process or our construction contracts, which could lead to the assertion of rights and remedies under the related contracts resulting in increases to the cost of the project, or any bolt-on expansions at our projects, or such contractor’s unwillingness to perform further work on our projects, or any bolt-on expansions at our projects, or to pay liquidated damages. For example, VGCP had disagreements regarding certain disputed costs and bonuses with Kiewit, our EPC contractor for the Calcasieu Project that were submitted to arbitration. Such disputes were fully resolved in 2024 and resulted in the payment by us of approximately $320 million, in the aggregate, to Kiewit.

In addition, if our current or intended contractors, or any of their parents or affiliates that provide performance guarantees, letters of credit or similar credit support, consummate any significant acquisitions, dispositions, restructurings or other strategic transactions, or become subject to bankruptcy or similar proceedings, our ability to complete our projects, or any bolt-on expansions at our projects, in accordance with our design and quality standards and on our anticipated schedule, and our ability to recover under any such performance guarantees, letters of credit or similar credit support, may be adversely affected.

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For example, in 2024 Zachry Industrial, Inc., one of the joint owners of KZJV, LLC, the EPC contractor for the Plaquemines Project, filed for bankruptcy protection under Chapter 11 of the U.S. bankruptcy code. While Zachry Industrial, Inc. successfully emerged from Chapter 11 proceeding in 2025 and we were able to successfully mitigate most of the bankruptcy’s impacts to the construction of the Plaquemines Project, there can be no assurance that any future bankruptcies of any of our contractors will not have a material adverse impact on any of our ongoing projects. Any such future contractor bankruptcies could result in material delays or termination of any of our projects and could have a material adverse impact on our ability to complete such projects on our anticipated schedule and budget, or at all.

If any contractor or supplier is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor or supplier. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We have not entered into all of the definitive agreements for our future projects and expansions, and there can be no assurance that we will be able to do so on a timely basis or on terms that are acceptable to us.

To date, we have not yet entered into all of the necessary definitive agreements with the key suppliers and contractors necessary for development and construction of all our future projects and expansions. While we have entered into the Baker Hughes Master Agreement and we have sufficient capacity for our currently planned future projects and expansion, we have not yet entered into EPC contracts or all other material supply agreements for all of our other future projects or expansions. We may not be able to successfully negotiate the outstanding necessary definitive contracts for our other future projects or expansions, on a timely basis or on terms or at prices that are acceptable to us. Our inability to negotiate and execute definitive agreements with such contractors on a timely basis or on terms acceptable to us could have a material adverse impact on our ability to complete our future projects and expansions, on our anticipated schedule and budget, or at all. Moreover, the development and construction of our future projects or any expansions thereof, may be delayed or they may not be built at all, and the construction cost of such future projects or expansions, may be greater than our current estimates.

Any of the foregoing could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Certain of our contractual arrangements relating to development and construction of our projects include termination rights that, if exercised, could have a material adverse impact on our projects.

Certain of our contractual arrangements relating to the development and construction of one or more of our projects include termination rights or changes to the applicable pricing, or will automatically expire, if certain conditions are not met by specified deadlines.

For example, under the Baker Hughes Master Agreement, if we fail to enter into purchase orders for the liquefaction systems and the power plant for our future development projects by certain mutually agreed dates or to begin making scheduled payments, then Baker Hughes’ obligations to supply such equipment will expire unless Baker Hughes agrees to extend those dates. In addition, Baker Hughes has agreed to reserve manufacturing capacity for purposes of fabricating equipment to be supplied under the agreement. While we have executed the applicable purchase orders for the Plaquemines Project and the CP2 Project, we have not yet executed any such purchase orders for any of our other future projects or expansions. If we do not execute applicable purchase orders by the applicable dates in the agreement, Baker Hughes may utilize the relevant manufacturing capacity for other purposes and delivery of equipment by Baker Hughes under the agreement could be delayed. Based on our anticipated project schedule, we currently expect that we will be in a position to deliver the purchase orders for our currently planned projects and bolt-on expansions to Baker Hughes by the applicable deadlines in the Baker Hughes Master Agreement, as such deadlines may be amended from time to time. However, if a project is delayed for any reason (including the reasons described elsewhere in this —Risk Factors section), Baker Hughes’ obligations with respect to the remaining equipment to be delivered would expire unless we either (i) deliver the applicable purchase order

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and commence making payments on the agreed schedule, or (ii) agree with Baker Hughes on an extension of the applicable deadline under the agreement. There can be no assurance that we would be able to negotiate any such extension on terms that are acceptable to us or at all, or that we will have the financial resources to make the scheduled payments with respect to a purchase order prior to commencement of construction and financing of the relevant project.

The termination of any of the definitive agreements we have entered into with contractors, or any change to the pricing under those agreements, could have a material impact on our ability to complete the Plaquemines Project, the CP2 Project, or any other future projects or expansions, on our anticipated schedule or budget, or at all.

Our estimated costs for our projects have been, and continue to be, subject to change due to various factors.

Our cost estimates for LNG facilities, related equipment and components, natural gas pipelines, LNG tankers, and other natural gas liquefaction and export facilities have been, and continue to be, subject to change due to many factors outside of our control. Such factors include, among other things, (i) inflationary factors, (ii) changes in commodity prices (particularly nickel and steel), (iii) escalating labor costs, (iv) supply chain availability, including the availability of critical components and increased costs to locate and procure alternatives, (v) labor disputes, (vi) tariffs, (vii) unexpected delays in construction or commissioning, (viii) unexpected repair, replacement, rectification and warranty work, and (ix) resolving contract closeout and true-up matters. Such factors have in the past resulted in, and may in the future result in, among other things, delays in construction or commissioning, repair or warranty work, cost overruns, and/or change orders under or amendments to existing or future construction contracts. Further, we may decide or be forced to enter into amendments to construction and/or supply contracts or submit change orders to the applicable contractor that could result in longer construction periods, higher costs, or both. We may also decide or be forced to expend additional funds in order to maintain construction schedules, complete construction and commissioning, or comply with existing or future environmental or other regulations. Additionally, our estimated costs for our projects do not include the potential costs of any new tariffs that have been implemented since December 31, 2025 or that may be implemented in the future or estimated costs for any potential bolt-on expansion opportunities that we may pursue in the future, including as a consequence of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government and the federal government’s decision to impose incremental baseline tariffs as a result. As a result, costs to achieve completion of LNG facilities, related equipment and components, natural gas pipelines, LNG tankers, and other natural gas liquefaction and export facilities may be higher, potentially materially, than our cost estimates. In the event we experience any such increases in estimated costs, delays or both, the amount of funding needed to complete an LNG facility, a phase thereof, related equipment and components, natural gas pipelines, LNG tankers, and other natural gas liquefaction and export facilities, could exceed our available funds and result in our failure to complete such projects or assets and thereby negatively impact our business and limit our growth prospects. See —We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs and —Risks Relating to Regulation and Litigation—If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.

We currently estimate that approximately $0.6 billion to $1.0 billion of the Total Project Cost for the Plaquemines Project has yet to be paid as December 31, 2025. This estimate is based in part on the target cost determined pursuant to the Plaquemines EPC Contracts and reflects increases related to, among other things, inflationary factors and efforts to maintain the project schedule while also reserving additional contingency funds (without giving effect to any commissioning cargo proceeds that may be utilized for project costs). Since FID of Phase 2 of the Plaquemines Project through the date of this Form 10-K, VGLNG has made several incremental equity contributions to VGPL in an aggregate amount equal to approximately $3.4 billion to address such increases in estimated Total Project Costs, and we may be required to make additional incremental equity contributions to the extent Total Project Costs exceed the low-end of the range of estimated Total Project Costs above and that such costs exceed the available project-level debt, equity financing and net proceeds from the sale of commissioning cargos. Pursuant to the Plaquemines Credit Facilities, if such contributions have been utilized to pay project costs

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for the Plaquemines Project, they are reimbursable by VGPL to VGLNG at our election upon satisfaction of certain conditions under the Plaquemines Construction Term Loan. The costs to achieve completion of the Plaquemines Project may be subject to further increases, which could be material, as a result of many factors outside of our control as described above. As a result, we may need to make additional equity contributions or raise additional project-level equity financing or debt financing in the future to fund any such increase in estimated Total Project Costs that exceeds our current contingency, and any such additional contributions or funding could be significant. Further, such cost estimates do not reflect the cost of any potential incremental bolt-on expansion capacity that we may elect to implement in the future.

We currently estimate that the Total Project Costs for Phases 1 and 2 of the CP2 Project will range from approximately $32.5 billion to $33.5 billion, including EPC contractor profit and contingency, owners’ costs and financing costs. Approximately $9.9 billion of the Total Project Cost for Phases 1 and 2 of the CP2 Project has been paid as of December 31, 2025. This estimate is based primarily upon our construction cost experiences with the Calcasieu Project and the Plaquemines Project, the pricing included in the CP2 EPC Contracts, and reflect the current inflationary environment as well as the fact that the pipeline for the CP2 Project is longer and more expensive than the pipelines for the Calcasieu Project and the Plaquemines Project. Our actual costs could vary significantly from our preliminary estimates depending on the terms we may agree to for those contracts. As a result, our cost estimates are only an approximation of the actual costs of construction and financing for the CP2 Project. Such cost estimates also do not reﬂect the cost of any potential incremental bolt-on expansion capacity that we may elect to implement in the future.

Further, the cost reimbursement arrangements under our existing EPC contracts provide that the EPC contractor will be reimbursed for all reimbursable costs incurred in connection with the relevant work, and while the EPC contractor’s profit margin will decrease as the amount of cost overrun increases, we are obligated to reimburse the EPC contractor for all reimbursable costs incurred under the EPC contract. However, EPC contracts that we enter into in the future may not include similar cost protections, which could lead to greater cost overruns for our other projects. Any increase in the construction costs for any of our projects could have an adverse impact on our business plan and the viability of the relevant project, and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our cost estimates with respect to any LNG facilities, related equipment and components, natural gas pipelines, LNG tankers, regasification facilities and other natural gas liquefaction and export facilities (including any expansion of an existing facility) we may decide to develop in the future would be subject to similar uncertainties and potential changes. For example, our cost estimates may continue to increase as we negotiate and finalize agreements with contractors for any such project.

In addition, our cost estimates do not reflect the potential impact of any changes to tariffs that have been announced or implemented since December 31, 2025 or that may be implemented in the future. Our project budget estimates included in this Form 10-K reflect all tariffs in place, and Section 232 exemptions secured, as of December 31, 2025, but do not reflect the potential impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on our Total Project Cost estimates. Certain of our products are foreign sourced and specified under our regulatory approvals, offering no domestically sourced alternative and potentially exposing us to the effects of any future tariffs that may be imposed. There can be no assurance as to the extent of any future tariffs, or the impact thereof on any of our estimates of Total Project Costs for our projects, which could have a material adverse effect on our construction budgets and limit our growth prospects. See Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Funding Requirements. Any increases in the construction costs for any of our projects could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

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Delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our current schedule for the completion of our projects may turn out not to be achievable. For example, our ability to complete our projects on the anticipated schedule is dependent upon our timely receipt and maintenance of required regulatory approvals and permits and upon various activities being completed by our contractors. Any significant construction or commissioning delay, as a result of regulatory issues or otherwise, could increase the total cost of the relevant projects and would cause a delay in the completion of the construction of our projects, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

In addition, delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our contracts. For example, we experienced unexpected delays in commissioning the Calcasieu Project related to certain necessary repairs and replacements. As a result, COD for the Calcasieu Project occurred on April 15, 2025, which is later than originally forecasted, after significant work related to commissioning, carryover completions, rectification, and certain other items was completed. Although we are currently generating revenue from sales of LNG commissioning cargos from the Plaquemines Project prior to commencing commercial operations, we will not generate any revenues or cash flows under our post-COD SPAs (including the intercompany excess capacity SPAs) until we have achieved COD at the project. Additionally, a failure to achieve the project completion date for a project by a date certain may result in an event of default under the related project financing, and, if such debt is accelerated, an event of default under our other financing agreements for that project or otherwise. Any such event of default would entitle the applicable debtholders to exercise certain remedies, including to accelerate the debt obligations under their respective debt instruments and to foreclose against all collateral that secures such debt, representing substantially all assets of the relevant project, which could seriously harm our business and lead to a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. See —Risks Relating to Our Indebtedness and Financing—Upon the occurrence of an event of default under our existing and future indebtedness, our lenders and the holders of our debt securities could elect to accelerate all or a portion of our debt. A delay in COD of the Plaquemines Project or the CP2 Project beyond a certain deadline could also result in an event of default under the Plaquemines Credit Facilities, the CP2 Credit Facilities, or the CP2 EBL Facility, respectively.

Any delay in a project’s ability to produce and load LNG for sale or delay in the completion of our projects could cause a delay in the receipt of proceeds projected from sales of LNG commissioning cargos, sales by VG Commodities, and/or from Contracted SPAs, or lead to a loss of one or more customers in the event of significant delays. For example, each of our post-COD SPAs provides that the counterparty may terminate that SPA in the event that such project has not achieved COD by the relevant deadlines, and such counterparties could also bring claims for contractual damages. In addition, each of our Firm-start SPAs requires that we pay certain cover damages if VG Commodities fails to make available LNG in the quantities set forth in the respective Firm-start SPA. We cannot assure you that we will have sufficient LNG capacity at our projects that is not otherwise committed to meet our obligations under our Firm-start SPAs if the relevant deadlines occur prior to COD of the relevant project. See —Risks Relating to Regulation and Litigation—We are involved, and may in the future become involved, in disputes and legal proceedings and —Risks Relating to Regulation and Litigation—If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock.

We are dependent on third party vendors and service providers to provide certain services and equipment to our projects.

We rely on third party vendors and service providers to provide certain services, supplies, products and equipment to our projects. We have entered into agreements with these third parties in connection with such

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services, supplies, products and equipment. However, the ability of our third party vendors and service providers to perform successfully under their agreements is dependent on a number of factors, including their ability to:

•maintain their own financial condition, including adequate working capital, and their ability to pay debt service and other liabilities;

•accurately estimate certain costs;

•meet quality or performance standards for third party equipment;

•procure equipment and supplies;

•execute requisite work and services efficiently; and

•attract, develop and retain skilled personnel.

If any third party vendor or service provider is unable or unwilling to perform according to the terms of its respective agreement for any reason or terminates its agreement, we may need to engage a substitute vendor or service provider. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Various economic and political factors, including opposition by environmental or other public interest groups, could negatively affect the timing or overall development, construction and operation of our projects, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our ability to commence liquefaction operations and produce LNG at our projects (other than the Calcasieu Project which commenced production of LNG in January 2022 and commercial operations in April 2025, and the Plaquemines Project, which commenced production of LNG in December 2024 and remains in the commissioning process) or any other natural gas liquefaction and export facility (or expansion of an existing facility) we may decide to develop in the future is dependent on the construction of the relevant facility (or expansion thereof), which will require the expenditure of significant amounts of capital that may exceed our estimates. The development and construction of our projects, as well as their commissioning prior to commercial operation, and any other natural gas liquefaction and export facilities (or expansion of an existing facility) that we may decide to develop in the future takes a number of years and may be delayed by factors such as:

•our ability to obtain or maintain necessary permits, licenses and approvals from regulatory agencies and third parties that are required to construct or operate the relevant project;

•our ability to enter into final ground leases for the relevant project site;

•the identification of any adverse issues with respect to the relevant project site;

•our ability to obtain right-of-way permits, servitudes or other similar property rights necessary to construct the pipelines required to interconnect the relevant project site with natural gas suppliers;

•our ability to administer our existing EPC Contracts and to successfully negotiate definitive agreements with EPC contractors for our future projects and expansions we develop, as well as with other advisors, contractors and consultants necessary for the development and construction of the relevant project in a timely manner for each of our projects;

•our ability to maintain or secure definitive Contracted SPAs for an adequate portion of the expected nameplate capacity of the relevant project, including for our future projects, and phases or expansions thereof, that are needed to support an FID for each such project, phase or expansion;

•our ability to secure necessary additional capital or financing on satisfactory terms, or at all, to develop our future projects and expansions thereof;

•the discovery of environmental conditions on the relevant project site that require investigation, remediation or other changes to the relevant project;

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•failure by our contractors to fulfill their obligations under their contracts relating to the development and construction of the relevant project, or disagreements with them over their contractual obligations;

•as construction progresses, we may decide or be forced to submit change orders to our contractors that could result in longer construction periods and higher than anticipated construction expenses;

•force majeure events, natural or man-made disasters, terrorist attacks or sabotage;

•shortages of materials or delays in the delivery of materials;

•weather conditions and impacts from potential climate change, hurricanes, severe weather events and other catastrophes, such as explosions, fires, floods and accidents;

•local and general economic and infrastructure conditions;

•political unrest or local community resistance or resistance by environmental groups and other advocates or impacts to indigenous peoples or impact by indigenous people to the development of the relevant project due to health, safety, environmental, or security or other concerns;

•our ability to attract sufficient skilled and unskilled labor, the existence of any labor disputes, our ability to maintain good relationships with our contractors in order to construct the relevant project within the expected parameters and the ability of those contractors to perform their obligations;

•economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;

•decreases in the price of LNG, which might decrease the expected returns relating to investments in LNG projects; and

•other risks inherent to the construction, expansion and operation of LNG facilities and other natural gas liquefaction and export facilities.

Many of these factors are outside of our control.

More generally, the regulatory approval process for many LNG and natural gas infrastructure projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to natural gas exploration and production, pipeline activities and associated environmental impacts, and increased opposition to the natural gas industry and related infrastructure. We have not yet obtained the requisite regulatory authorizations for all of our planned projects. For instance, additional authorizations are still required from FERC for the CP2 Project as we proceed with its construction and commissioning consistent with the terms and conditions in FERC’s authorization. Furthermore, while we have proposed to increase the authorized production capacity of both the Plaquemines and CP2 projects, neither FERC nor DOE has yet authorized those increases. Similarly, we only recently applied for authorizations for the Plaquemines Expansion Project. The requisite regulatory authorizations for all of these projects potentially may be delayed, conditioned, or even denied.

Furthermore, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by activists requesting that issued approvals and authorizations be stayed, reversed, and vacated. Increased opposition and regulatory challenges may harm our ability to obtain and maintain necessary regulatory approvals. For example, on November 27, 2024, in response to project opponents challenging FERC’s authorization for the CP2 Project, FERC issued an order on rehearing that generally rejected the arguments opposing the CP2 Project, but partially “set aside” its prior analysis to initiate a supplemental environmental review of certain discrete potential impacts of the project. FERC subsequently affirmed the authorization in subsequent orders in 2025 but the supplemental environmental review delayed on-site construction. The opponents of the CP2 Project have filed petitions with the U.S. Court of Appeals for the D.C. Circuit challenging FERC’s orders authorizing the CP2 Project. In addition, in August 2025, environmental groups filed a lawsuit in the U.S. Court of Appeals for the Fifth Circuit challenging permits issued by the Louisiana Department of Environmental Quality for the CP2 Project. Furthermore, in February 2026, environmental groups filed another appeal in the Court of Appeals for the D.C. Circuit challenging DOE’s order authorizing exports to Non-FTA Nations by the CP2 Project. There can be no assurances as to the outcome of such pending proceedings.

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There can be no assurance that our existing or future regulatory approvals will not be subject to other legal challenges, or that such approvals will not be re-examined vacated, withdrawn, overturned, altered or otherwise modified in a manner adverse to the development, construction or operation of one or more of our projects or to our business more generally. If we are required to modify our activities as a result of the pending judicial appeals or other changes to our existing regulatory approvals, the impact could increase our project costs, delay our project timelines, affect our ability to complete our planned projects, or result in claims from third parties if we are unable to meet our commitments under our pre-existing commercial agreements, all of which could have a material adverse effect on our business. Any delay in completion of our projects that prevents us from producing and loading LNG when anticipated would also cause a delay in the receipt of revenues therefrom, potentially require us to pay damages to selected customers with whom we have entered into definitive SPAs, or, in the event of significant delays beyond certain time periods, permit customers to terminate their contractual obligations to us.

In addition, the successful completion of our projects is subject to the risk of cost overruns, schedule delays, weather disruptions, labor disputes and other factors, any of which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our business could be materially and adversely affected if we do not secure the right or if we lose the right to situate certain lateral pipelines, longer-haul pipelines or any other pipeline infrastructure for any of our projects on property owned by third parties, or if we do not complete the construction of those pipelines in a timely fashion.

We expect to obtain access to the natural gas required for the operation and commissioning process for our projects through certain lateral and longer-haul pipeline connections that we plan to construct as part of those projects, each of which will connect the relevant LNG facility to one or more third-party pipelines. While the lateral pipelines for both the Calcasieu Project and the Plaquemines Project are complete, much of this contemplated pipeline infrastructure has not been completed. As we are expanding our development footprint with the our future projects and expansions, these projects’ production capacities will require natural gas volumes that necessitate the construction of longer interstate and intrastate pipelines that provide incremental access and delivery capability from the Permian, Haynesville, Western Haynesville, Eagle Ford, mid-continent shale, and other formations. We plan to construct significant 48-inch diameter, compressed pipeline infrastructure, both independently and in partnership with certain qualified third parties, sufficient to source the required natural gas for these projects from primarily the Permian, Haynesville and Western Haynesville shale plays. Timely completion of such pipelines will be subject to numerous risks, such as interface risks with our third-party partners, weather delays, accidents, inability to obtain required rights-of-way and servitudes, and regulatory approvals. Opposition to regulatory approvals for the pipeline projects could delay or prevent their completion, which could have an adverse impact on our business and operations

We do not expect to own or lease the vast majority of the tracts of land on which we expect to construct the pipeline infrastructure that will connect our projects to third-party pipelines and other sources of natural gas. As a result, we need to secure servitudes, rights-of-way and similar rights necessary for the construction of that pipeline infrastructure. Although we have obtained permanent servitudes in respect of all of the land on the TransCameron Pipeline route for the Calcasieu Project, the Gator Express Pipeline route for the Plaquemines Project and substantially all the land for the CP Express Pipeline for the CP2 Project, certain tracts in respect of which we have obtained such rights are currently burdened by mortgages that would be superior to our rights. While the servitudes we obtain generally contain clauses that require the relevant landowners to use commercially reasonable efforts to provide us with subordination, non-disturbance and attornment agreements, or the SNDAs, if we request them, there can be no assurance that any such SNDAs, or any other measures we take, will result in us having adequate real property rights with respect to these tracts. Moreover, with respect to the other pipelines that we plan to develop, we have not yet obtained all of the rights necessary to construct the pipeline infrastructure expected to connect those projects to third-party pipelines and other sources of natural gas, and there can be no assurance that we will be able to obtain the necessary property rights on terms satisfactory to us, or at all.

As a result of these factors, our pipeline infrastructure for our future projects and expansions is subject to the possibility of increased costs to obtain necessary land use rights. If we were unable to obtain those rights or if we

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were to lose any such rights with respect to a project, or if we were required to relocate any of our pipeline infrastructure, our business could be materially and adversely affected.

There is no assurance that our projects will receive the local government and community support required for construction.

The development and construction of our projects requires support and approval from local governments with jurisdiction over the project sites and support from the communities in which they are located. While we believe we have requisite local government and community support in Cameron Parish and Plaquemines Parish, where our projects our located, there is no assurance that we can maintain such support or that we will receive such support for other projects, including any expansions thereof, we may develop in the future. Any failure to obtain or maintain the requisite local government and community support for our projects, or for any other natural gas liquefaction and export facility we may decide to develop in the future, could have a material adverse effect on our ability to develop and construct that project on our anticipated schedule, or at all.

Our real property rights in the sites for our projects or any other natural gas liquefaction and export facilities that we may decide to develop in the future may be adversely affected by the rights of others that are superior to those of the grantors of our real property rights.

The Calcasieu Project, the Plaquemines Project, the CP2 Project, and our other future projects and expansions thereof, and our pipeline development projects that we may decide to develop in the future are likely to be located on land subject to long-term servitudes, leases, rights of way and similar agreements with landowners. The ownership interests in the land subject to these servitudes, leases, rights-of-way and similar agreements may be subject to mortgages securing loans or other liens (such as tax liens) and other servitudes, lease rights and rights-of-way of third parties that were created prior to our servitudes, leases and rights-of-way. As a result, certain of our rights under these servitudes, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties.

We perform title searches, obtain title insurance and enter into non-disturbance agreements to protect ourselves against these risks. Such measures may, however, be inadequate to protect our operating projects against all risk of loss or impairment of our rights to use the land on which our existing and future projects are located.

Any such loss or curtailment of our rights to use the land on which our projects or any other future project is located, and any increase in rent due on such lands, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects and could also adversely affect our ability to secure necessary additional capital for the relevant project.

The natural gas liquefaction system and mid-scale design we utilize at our projects are the first of such sized modules developed by us and Baker Hughes, and there can be no assurance that these modules, or our projects, will achieve the level of performance or other benefits that we anticipate over the long term.

We are constructing our projects using a natural gas liquefaction system provided by Baker Hughes that is deployed in a unique mid-scale, factory-built configuration that we developed. While Baker Hughes has developed liquefaction systems utilizing both larger and smaller modules before, the specific liquefaction modules that we are using are the first of such sized modules produced by Baker Hughes, and accordingly the configuration, production, transportation, installation and commissioning of such sized modules has not yet been tested in LNG projects, except for the Calcasieu Project and the Plaquemines Project. As a result, there may be issues with respect to this design that have not yet been identified, notwithstanding the current production of LNG at the Calcasieu Project and the Plaquemines Project, that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. While Baker Hughes has an obligation to ensure the liquefaction systems meet minimum performance guarantees, there can be no assurance that the liquefaction system is able to satisfy the minimum performance guarantees or maintain such performance guarantees throughout the operating life of a facility.

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We have the right under the Baker Hughes Master Agreement to require Baker Hughes to enter into a long-term service agreement on specified terms with respect to long term maintenance, repair, and servicing of the liquefaction, power, and booster compressor equipment it supplies. While we have entered into a long-term service agreement with Baker Hughes for the Calcasieu Project and the Plaquemines Project, under which Baker Hughes guarantees the minimum performance and operating availability of certain liquefaction and power systems it supplies, we have not yet negotiated the final terms for any such long-term service agreement for any other projects. Notwithstanding our rights under the Baker Hughes Master Agreement, there can be no assurance that we will enter into the long-term service agreement with Baker Hughes on the same terms as we currently anticipate. If we encounter issues with the new technology, including, for example, higher operating or maintenance expenses, lower performance standards or more downtime than we currently anticipate, our projects may not be able to produce the quantity or volume of LNG we anticipate and our projects may be delayed and the financial viability of our projects may be adversely impacted. Any of these factors could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

The phased commissioning start-up of our projects will subject us to additional risks.

The unique configuration of our LNG projects necessitates a phased commissioning start-up process for each of our projects (and phases thereof) that will generally result in a longer commissioning process. The length of any commissioning process depends on a number of factors related to equipment performance and the ability to establish reliable and safe operations for that equipment and the facility as a whole. For example, once we have sufficient power to operate the first pre-treatment unit, and the first LNG storage tank and first gas pre-treatment unit have been installed for a particular project, we generally begin the commissioning start-up of the relevant equipment on a phased basis. This sequential commissioning of the liquefaction trains, power island system, pre-treatment system, and other equipment for a project is subject to several risks, some of which may be unknown to us.

For example, the simultaneous construction of a particular LNG facility and production of LNG at that facility could subject us and our third-party contractors to additional safety hazards, as well as additional costs related to the management of those safety hazards during the phased commissioning start-up of a facility. To successfully implement our phased commissioning start-up, our EPC contractors will be required to develop and implement a safe work plan. Furthermore, we will require additional regulatory approvals from FERC for all of our construction and commissioning activities, including approval of our EPC contractor’s safe work plan, in order to implement our phased commissioning start-up at a facility before construction has been completed. Any delays in implementing any of the measures required for the phased start-up of our facilities or in obtaining the necessary regulatory approvals, and any additional costs associated with the phased start-up of our facilities, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We are and will be relying on third-party engineers to estimate the future capacity ratings and performance capabilities of our projects, and these estimates may prove to be inaccurate.

We are and will be relying on third parties, principally the construction contractors, for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of our projects. If any of our liquefaction facilities for our projects, when completed, fails to have the capacity ratings and performance capabilities that we intend, the estimates set forth in this Form 10-K may not be accurate. Failure of any of our liquefaction facilities for our projects to achieve our intended capacity ratings and performance capabilities could prevent us from satisfying the performance tests required in order to achieve COD start dates under our post-COD SPAs and cause the quantity of LNG we produce to fall short of our contractual delivery obligations to customers and could have a material adverse effect on our business, contracts, operating results, financial condition, cash flow, liquidity, financing requirements and prospects. Further, we will not generate any revenues or cash flows under our post-COD SPAs or from sales to third parties of excess capacity covered by the intercompany excess capacity SPAs, in each case until we have achieved COD for the relevant project.

Additionally, satisfying required performance tests is a condition precedent for project completion under our project financing, and a failure to achieve the project completion date for a project by a date certain may result in an

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event of default under those project financing documents. If such debt is accelerated, it may also result in an event of default under our other financing agreements for that project or otherwise. Further, under certain financing agreements we may be required to (i) maintain in effect all material project agreements, including the relevant EPC contract, for a particular project and (ii) comply in all material respects with their payment and other material obligations under the material project agreements for such project, and any breach of such requirements may, after any applicable cure periods, result in an event of default under our other financing agreements for that project or otherwise. Any such event of default would entitle the applicable debtholders to exercise certain remedies, including to accelerate the debt obligations under their respective debt instruments. See —Delays in the construction of our projects beyond the estimated development periods could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Construction and operations of natural gas pipelines and lateral pipeline connections for our projects are subject to a number of regulatory approvals, development risks, operational hazards and other risks, which could cause cost overruns and delays and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We have completed the construction of two of our natural gas pipeline projects, the TransCameron Pipeline and the Gator Express Pipeline. Construction and operations of our future, planned natural gas pipelines and pipeline connections for our projects, including the CP Express natural gas pipeline, which is permitted and under construction, and the pipelines required for our other future projects and expansions, which are not yet permitted, are subject to the risks of delay or cost overruns inherent in any construction project resulting from numerous factors, including, but not limited to, the following:

•failure to obtain and maintain relevant approvals and permits from governmental and regulatory agencies;

•difficulties or delays in obtaining, or failure to obtain, sufficient equity or debt financing on reasonable terms;

•difficulties in engaging qualified contractors necessary for the construction of natural gas pipelines and lateral pipeline connections for any of our projects;

•shortages of equipment, material or skilled labor;

•natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents and terrorism;

•unscheduled delays in the delivery of ordered materials;

•EPC productivity factor realization, work stoppages and labor disputes;

•difficulties or delays in obtaining, or failure to obtain, sufficient real property interests on which to construct and locate the pipelines and associated facilities;

•unexpected or unanticipated need for additional improvements;

•unexpected additional material quantities and labor hours; and

•adverse general economic conditions.

Delays beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts that are currently estimated, which could require us to obtain additional sources of financing to fund the activities. Any delay in completion of the pipelines may also cause a delay in commencement of commercial operations of our projects even if the projects are substantially complete for commercial operations. As a result, any significant construction delay in construction of the natural gas pipelines and lateral pipeline connections, whatever the cause, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

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If third-party pipelines and other facilities interconnected to our pipelines and facilities are or become unavailable to transport natural gas or if there are any reductions in the capacity of, or the allocations to, interconnecting third-party pipelines, this could cause a reduction of volumes transported to our facilities and could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

We depend and will continue to depend upon third-party pipelines and other facilities interconnecting with our projects to provide material gas delivery options to our liquefaction and export facilities. We have entered into multiple agreements with various pipelines for the transport of natural gas to the Calcasieu Project and the Plaquemines Project. The transport of natural gas to the Calcasieu Project and the Plaquemines Project has been secured through a portfolio of approximately 10- to 20-year transportation arrangements. The CP2 Project has also entered into agreements for firm transportation capacity with third parties and CP Express. We are also in the process of contracting for, or developing, the additional required transportation capacity in support of our other projects. We do not have any control over the operation, development, expansion, or maintenance of these third-party pipelines or certain other third-party pipeline facilities that may be interconnected with our projects in the future.

The design, construction and operation of natural gas pipelines are highly regulated activities. Approvals of FERC under Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate an interstate natural gas pipeline, and those approvals may be subject to judicial appeals. Intrastate pipelines not regulated by FERC under the NGA nevertheless require other governmental approvals. Neither we nor our SPA customers have any control over the ability of third-party pipelines to obtain, maintain or comply with any such regulatory approvals and permits.

Additionally, the capacity on interconnecting pipelines may not be sufficient to accommodate additional liquefaction trains we may construct if we undertake an expansion of our project facilities, including the potential bolt-on expansion for the Plaquemines Project. Further, if we need to replace one or more of our interconnection agreements or enter into additional agreements, we may not be able to do so on commercially reasonable terms or at all.

If we are unable to secure any necessary pipeline interconnections, or if any third-party pipelines or pipeline connections that we currently depend upon were otherwise to become unavailable for current or future volumes of natural gas due to a failure to obtain or maintain regulatory approvals or permits, repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas from producing regions to our projects could be restricted, which could have a material adverse effect on our business and operations, and on our ability to perform under the SPAs.

Delays in deliveries of newbuild LNG tankers, and increases in price or building costs, could harm our operating results.

The delivery of newbuild LNG tankers to us could be delayed, not completed or cancelled, which could delay or eliminate our ability to optimize contracts with spot and term customers seeking delivered LNG and prevent us from realizing the anticipated benefits of operating our LNG tanker fleet. Deliveries may be delayed or cancelled due to, among other things, quality, warranty, or engineering issues, failure to meet contractual specifications, changes in governmental regulations or maritime standards, delays in equipment delivery by third-party suppliers, labor disruptions, shipyard capacity constraints, bankruptcy or liquidity issues of shipbuilders or sellers, political or economic disturbances in the country or region where vessels are constructed, weather or catastrophic events, shortages of construction materials such as steel, or our inability to satisfy payment or other contractual obligations. In addition, third parties from whom we charter LNG tankers may in the future fail to deliver vessels on time or at all, which could adversely affect our operations.

Our contracts for newbuild LNG tankers subject us to counterparty and cost-increase risks. The final cost of LNG tankers may increase pursuant to adjustment provisions in our contracts, and if we fail to make required payments, we could experience delivery delays, defaults under our acquisition agreements or the loss of rights to

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acquire vessels and amounts previously paid. Any delay in, or shortfall relating to, the construction of our LNG tanker fleet could require us to charter third-party vessels at potentially higher costs and on less favorable terms, which could have a material adverse effect on our business, contracts, financial condition, results of operations, cash flows, liquidity and prospects. In addition, the contracts for newly built vessels subject us to counterparty risk. The ability and willingness of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control, including, among other things, general economic conditions, the condition of the LNG shipping industry, the overall financial condition of our counterparty, prevailing prices for LNG cargos, rates received for specific types of LNG tankers, and various expenses. If our counterparties fail to meet their obligations to us or attempt to renegotiate our agreements, if our counterparties fail to deliver an LNG tanker in accordance with the terms of the relevant contract, or if a counterparty otherwise fails to honor its obligations to us under a contract, we could sustain significant losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Delays in the delivery, or shortfalls in the construction and acquisition of, our LNG tanker fleet, could require us to charter third-party LNG tankers, which could expose us to additional liability and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Management and operation of our LNG tanker fleet and the charter of third-party vessels involve significant risks.

In addition to the seven newbuild LNG tankers that have been delivered and are already in operation, we have entered into contracts to acquire two additional LNG tankers that are currently under construction and will be delivered on a rolling basis in 2026, which will be used to provide additional optionality to short-, medium- or long-term customers and to service our single existing post-COD DPU SPA and any future SPAs where LNG is sold on a delivered basis. Following delivery of each of these LNG tankers, we plan to manage and operate such tankers through our subsidiaries. In addition, we have chartered, and anticipate that we will continue to charter, LNG tankers to supplement our wholly-owned fleet. We have been building our team to manage and operate our fleet of LNG tankers, and as a result we are exposed to various operational risks as we continue to expand that team and grow our fleet of LNG tankers. We are also exposed to operational risks where we charter third-party vessels. For example, we are exposed to the following risks with respect to the operation of LNG tankers:

•the Company’s limited track record with managing and operating our own LNG tanker fleet;

•performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

•breakdowns or failures of equipment or shortages or delays in the delivery of supplies;

•risks related to operators and service providers of tanker or tugs used in our operations;

•operational errors by us or any contracted facility, port or other operator of related infrastructure.

•failure to maintain the required government or regulatory approvals, permits or other authorizations;

•accidents, fires, explosions or other events or catastrophes;

•a lack of adequate and qualified personnel to adequately crew and operate the LNG tankers;

•potential labor shortages, work stoppages or labor union disputes;

•our potential inability to recruit and retain a team to manage and operate our fleet of LNG tankers and any chartered third-party vessels;

•weather-related or natural disaster interruptions of operations;

•pollution, release of or exposure to toxic substances or environmental contamination, including marine accidents and spills, affecting operations;

•inability, or failure, of any counterparty to any fleet-related agreements to perform their contractual obligations; and

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•a lack of demand for shipping services by our customers after we receive delivery of our LNG tankers or charter a third-party vessel.

The risks related to the management and operation of LNG tankers are complex and technically challenging and subject to mechanical risks and problems. In particular, marine LNG operations are subject to a variety of risks, including, among others, marine disasters, piracy, bad weather, mechanical failures, environmental accidents, epidemics, grounding, fire, explosions and collisions, human error, and war and terrorism. An accident involving our cargos or any of our LNG tankers or chartered third-party vessels could result in death or injury to persons, loss of property or environmental damage; delays in the delivery of cargo; loss of revenues; governmental fines, penalties or restrictions on conducting business; higher insurance rates; and damage to our reputation and customer relationships generally. Any of these circumstances or events could increase our costs or lower our revenues.

If our LNG tankers, or any vessels we charter, suffer damage as a result of such an incident, they may need to be repaired. Repairs and maintenance costs for LNG tankers are difficult to predict and may result in higher than anticipated operating expenses or require additional time or capital expenditures. The loss of earnings or costs to charter replacement tankers while these LNG tankers are being repaired could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. In addition, if one of our LNG tankers, or any vessels we charter, were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage and potential liability, including regulatory penalties, sanctions, fines and litigation, could have a material adverse effect on our reputation, our current or future business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. An accident involving one of our LNG tankers would also distract our management team.

We expect our offshore operating expenses to depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control. Other factors, such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements, could also increase operating expenditures.

If we fall short of our goals in acquiring or maintaining our LNG tanker fleet, we may be required to charter additional vessels from third parties. Additionally, our ability to charter vessels from third parties could be affected by potential shortages of LNG tankers worldwide. See —Risks Relating to the LNG Industry—There may be shortages of LNG tankers worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. As the overall trends steer toward more regulation and more stringent operating requirements, we are subject to the risk that our LNG tankers, or any chartered vessels we employ could fall out of compliance with such regulations. The terms of any charter agreement into which we may enter to substitute for shortfalls in our own LNG tanker fleet may require that we bear some or all of the associated costs with maintaining compliance with such regulations. While we believe we are appropriately situated to minimize this risk given the building of our own LNG tanker fleet, we cannot assure you that such factors will not have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Future occurrences of any of the foregoing or any other events of a similar or dissimilar nature could have a material adverse impact on our business, financial condition and results of operations.

The construction of our projects, and our operations, are subject to significant hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our projects is and will be subject to the inherent risks associated with these types of operations, including the following:

•explosions, pollution, releases of toxic substances;

•fires, hurricanes and adverse weather conditions and other weather-related interruptions of construction and/or operations;

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•facilities performing below expected levels of efficiency;

•breakdown, failures or mechanical issues affecting our equipment;

•operational errors by vessel or tug operators;

•operational errors by us or any contracted facility operator; and

•labor disputes.

The occurrence of any of these events could require us, or enable our counterparties, to declare a force majeure under our material construction contracts or other construction contracts or SPAs or otherwise could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We may enter into certain arrangements to share the use and operations of facilities among projects, which would require us to meet certain conditions under our project-level financing documents. Despite the protection provided by such financing documents, the nature of such sharing arrangements is not currently known and may limit our operational flexibility, use of land and/or facilities.

We are permitted under certain of our project-level financing documents to enter into sharing arrangements with one or more entities that are developing or own one or more liquefaction trains and related facilities among our various projects. Such sharing arrangements may involve sharing the use and capacity of land and facilities with such adjacent project owners, including pooling the capacity of liquefaction trains, sharing common facilities, such as power generating facilities, storage tanks and berths, and sharing capacity of the pipeline interconnections, to the extent permitted under the relevant financing documents. We may also, subject to regulatory approvals, transfer and/or amend previously obtained permits and other authorizations or applications such that they may be used by such other project owners with which we may have sharing arrangements.

As future arrangements that would only be fully determined if the circumstances arise, there is uncertainty as to the full scope and impact of these sharing arrangements. Our project-level financing documents require us to meet certain conditions in respect of such sharing arrangements. These sharing arrangements would be subject to quiet enjoyment rights for the relevant project owners.

Risks Relating to Intellectual Property, Data Privacy and Cybersecurity

Hostile cyber intrusions, or other issues with our information technology, could severely impair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have a material adverse effect on our business.

Our projects and any other natural gas liquefaction and export facilities (including any expansion of existing facilities) we may decide to develop in the future include assets deemed by FERC to constitute critical energy infrastructure, the operation of which is dependent on our information technology, or IT, systems. The IT systems that run our natural gas liquefaction and export facilities are not completely isolated from external networks. A successful cyber-attack on the systems that will control our assets could severely disrupt business operations, preventing us from serving customers or collecting revenues, as well as expose us to other risks. Additionally, a successful cyber-attack against a pipeline which supplies our LNG facilities could affect our ability to obtain physical delivery of sufficient natural gas to operate at full capacity, or at all.

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Other exposure to various types of cyber-attacks, such as malware, ransomware, viruses, denial of service attacks, social engineering, password spraying, credential stuffing, phishing or other malicious or fraudulent acts, as well as human error or malfeasance, could also potentially disrupt our operations. Artificial intelligence, or AI, both expands the attack surface and arms adversaries with more sophisticated tools for attacks, escalating the scale and unpredictability of cyber threats. Risks include AI-amplified attacks, third-party vendor vulnerabilities, and data breaches/unauthorized access. Such security threats are increasing in frequency and sophistication and pose a risk to the security of our IT systems and the confidentiality, availability and integrity of the information we process and maintain. We also may be vulnerable to interruption and breakdown by fire, natural disaster, power loss, telecommunication failures, internet failures and other catastrophic events. We may experience occasional system interruptions and delays that make our IT systems unavailable or slow to respond, including the interaction of our IT systems with those of third parties.

Cybersecurity threats are persistent and evolve quickly, and we may in the future experience such threats. Such threats have increased in frequency, scope and potential impact in recent years because of the proliferation of new technologies, including artificial intelligence, and the increased number, sophistication and activities of perpetrators of cyber-attacks. Since the techniques used to obtain unauthorized access to or to sabotage IT systems change frequently and are often not recognized until after they are launched against a target, we may be unable to anticipate these techniques or to implement adequate preventative measures. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation and customer relationships. We maintain and update a cybersecurity program to safeguard our IT systems, including those that run and connect to IT systems that run our natural gas liquefaction and export facilities. Failure to continue to do so effectively could expose our IT systems to increased risk of a successful cyber-attack.

We are also reliant on the security practices of our third-party service providers, business partners, vendors, and suppliers, which may be outside of our direct control. These third parties, and the services provided by these third parties, which may include cloud-based services, are subject to the same risk of experiencing, and have experienced, outages, other failures and security breaches described above. IT systems provided by third parties on which we rely also may be difficult to integrate with other tools due to their complexity, resulting in high data inconsistency and incompatibility. If these third parties fail to adhere to adequate security practices, or experience a breach of their systems, the information of our employees, consumers and business associates may be improperly accessed, used, disclosed or otherwise processed, and we may potentially be held liable, or alleged to be liable, under certain laws or contractual obligations for the acts or omissions of our third-party providers. Any loss or interruption to our IT systems or the services provided by third parties could adversely affect our business, financial condition and results of operations.

We maintain property and casualty insurance that may cover certain damage caused by potential cybersecurity incidents. However, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available as discussed under —Risks Relating to Our Business—We are unable to insure against all potential risks and may become subject to higher than expected insurance premiums. In addition, we retain certain risks as a result of insurance through our captive insurance. As a result, a significant cyber incident involving our business or operational control systems or related infrastructure, or that of third-party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions, delay financial or compliance reporting or otherwise disrupt our business. These impacts could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Changes in laws, rules or regulations relating to data privacy and security, or any actual or perceived failure by us to comply with such laws, rules and regulations, or contractual or other obligations relating to data privacy and security, could adversely impact our business.

We are, and may increasingly become, subject to various laws, directives, industry standards, rules and regulations, as well as contractual obligations, related to data privacy and security in the jurisdictions in which we operate. The regulatory environment related to data privacy and security is increasingly rigorous, with new and

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constantly changing requirements, and is likely to remain uncertain for the foreseeable future. These laws, rules and regulations may be interpreted and applied differently over time and from jurisdiction to jurisdiction, and it is possible that they will be interpreted and applied in ways that may have a material adverse effect on our results of operations, financial condition and cash flows.

In the United States, various federal and state regulators, including governmental agencies like the Federal Trade Commission, have adopted, or are considering adopting, laws, rules and regulations concerning personal information. Certain state laws may be more stringent or broader in scope, or offer greater individual rights, with respect to personal information than federal, international or other state laws, and such laws may differ from each other, all of which may complicate compliance efforts. A number of similar laws in other states have already taken effect or will become effective in the near future. State laws are changing rapidly and in the future Congress may pass a new comprehensive federal data protection law, which may add additional complexity, variation in requirements, restrictions and potential legal risks.

All of these evolving compliance and operational requirements impose significant costs on us, which are likely to increase over time. Any failure or perceived failure by us to comply with any applicable federal, state or similar foreign laws, rules and regulations relating to data privacy and security could result in damage to our reputation and our relationship with our customers, as well as proceedings or litigation by governmental agencies or individuals, including class action privacy litigation in certain jurisdictions, which could subject us to significant fines, sanctions, awards, penalties or judgments, operational changes, and negative publicity that could adversely affect our reputation, results of operations and financial condition.

If we are unable to obtain, maintain, protect and enforce our intellectual property rights, our business may be adversely affected.

We rely on a combination of intellectual property rights, including know-how and trade secrets, to establish, maintain and protect our intellectual property and other proprietary rights. For example, under our agreements with Baker Hughes, we own certain know-how and trade secrets relating to aspects of the liquefaction systems.

We cannot guarantee that our efforts to obtain, maintain, protect and enforce such rights are adequate or that we have secured, or will be able to secure, appropriate permissions or protections for all of the intellectual property rights we use or rely on. Furthermore, any such intellectual property rights may be challenged, invalidated, circumvented, infringed, misappropriated or otherwise violated. Any challenge to our intellectual property rights could result in them being narrowed in scope or declared invalid or unenforceable. In addition, other parties may independently develop technologies that are substantially similar or superior to ours and we may not be able to stop such parties from using such independently developed technologies to compete with us. If we fail to adequately obtain, maintain, protect and enforce our intellectual property rights, we may lose an important advantage in the markets in which we compete. While we seek to enter into confidentiality, intellectual property assignment and non-compete agreements, as applicable, with our employees, contractors and other third parties, we may fail to enter into such agreements with all relevant parties, such agreements may not be self-executing or enforceable, and we may be subject to claims that such parties have misappropriated the trade secrets or other intellectual property or proprietary rights of their former employers or other third parties. Additionally, these agreements may not provide meaningful protection for our trade secrets and know-how in the event of unauthorized use or disclosure.

We also may be forced to bring claims against third parties to determine the ownership of what we regard as our intellectual property or to enforce our intellectual property against its infringement, misappropriation or other violation by third parties. Additionally, third parties may initiate legal proceedings alleging that we are infringing, misappropriating or otherwise violating their intellectual property rights. The outcomes of such intellectual property-related proceedings are often unpredictable. Regardless of whether any such proceedings are resolved in our favor, such proceedings could cause us to incur significant expenses and could distract our personnel from their normal responsibilities. Furthermore, our intellectual property rights and the enforcement or defense of such rights may be affected by developments or uncertainty in laws, rules and regulations related to intellectual property rights. Any of the foregoing could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

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Risks Relating to Ownership of Our Class A Common Stock

VG Partners has significant influence over us, including control over decisions that require their approval, which could limit your ability to influence the outcome of key transactions, including a change of control.

Our Class B common stock has ten votes per share and our Class A common stock has one vote per share. Holders of shares of our Class B common stock will vote together with holders of our Class A common stock as a single class on all matters on which stockholders are entitled to vote generally, except as otherwise required by law. As of February 13, 2026, VG Partners owned 1,968,604,458 shares of Class B common stock or 100% of all shares of Class B common stock then outstanding. As a result, VG Partners holds approximately 97.6% of the combined voting power of our Class A common stock and our Class B common stock and is able to influence or control matters requiring approval by our stockholders, including the election of directors and the approval of mergers or other extraordinary transactions. Further, the share of combined voting power held by VG Partners may increase in the future as a result of any repurchase of outstanding Class A common stock that we may decide to pursue from time to time, or any acquisition of our Class A common stock by VG Partners or our Founders, who control VG Partners (including upon vesting or exercise of equity awards). Furthermore, under Delaware law and our amended and restated certificate of incorporation and amended and restated bylaws, VG Partners is able to take certain actions by written consent of the majority of the combined voting power of our common stock without calling a meeting of stockholders. In addition, as the holder of a majority of the combined voting power of our common stock, VG Partners currently has the sole ability to elect the board of directors. Other holders of our Class A common stock, so long as they do not own a majority of the combined voting power, have only minority voting rights on matters affecting our business.

VG Partners may have interests that do not align with the interests of our other stockholders, including with regard to pursuing acquisitions, divestitures, and other transactions that, in their judgment, could enhance their equity investment, even though such transactions might involve risks to our other stockholders. VG Partners has effective control over our decisions to enter into such corporate transactions regardless of whether others believe that the transaction is in our best interests. Such concentration of voting control may have the effect of delaying, preventing, or deterring a change of control of us, could deprive stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of us, and might ultimately affect the market price of our Class A common stock.

There is the possibility of significant fluctuations in the price of our Class A common stock.

Many factors have in the past, and may in the future, cause the price of our Class A common stock to fluctuate substantially, which may limit or prevent investors from readily selling their shares of our Class A common stock and may otherwise negatively affect the liquidity of our Class A common stock. These factors include:

•the ongoing development and sustainability of an active, liquid market for our Class A common stock;

•the price of LNG and natural gas;

•the completion of the regulatory approval process required to construct and operate our projects and the timing of any such completion;

•the commencement and timely completion of construction of our projects;

•ongoing and threatened arbitration proceedings with some of our customers;

•our quarterly or annual earnings or those of other companies in our industry;

•actual or potential non-performance by any customer under any LNG sales contract that we may enter into;

•announcements by us or our competitors of significant contracts;

•changes in accounting standards, policies, guidance, interpretations or principles;

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•market conditions in the broader stock market in general, or in our industry in particular;

•future sales of our Class A common stock;

•investor perceptions of the investment opportunity associated with our Class A common stock relative to other investment alternatives;

•the public’s response to press releases or other public announcements or filings by us or third parties, including our filings with the SEC;

•regulatory developments;

•geopolitical developments;

•litigation and governmental investigations; and

•other factors described in these "Risk Factors" and elsewhere in this Form 10-K.

Accordingly, any investor may lose money or their investment in us and may be required to hold their shares for an indefinite period of time. In addition, when the market price of a stock has been volatile, holders of that stock frequently institute securities class action litigation against the company that issued the stock. For example, several putative class actions have been filed against us in connection with the IPO. See —Risk Factors—Risks Relating to Regulation and Litigation—We are involved, and may in the future become involved, in disputes and legal proceedings. We could incur substantial costs defending the class action and any other lawsuit our stockholders may bring against us. Such lawsuits could also divert the time and attention of our management from our business.

The trading market for our Class A common stock may also be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrade our stock, or if our results of operations do not meet their expectations, our stock price could decline.

If we become a United States real property holding corporation, or a USRPHC, non-U.S. shareholders may be subject to U.S. federal income tax in connection with the disposition of shares of our Class A common stock.

A non-U.S. holder of our Class A common stock not otherwise subject to U.S. federal income tax on gain from the sale or other disposition of our Class A common stock may nevertheless be subject to U.S. federal income tax with respect to such sale or other disposition if we are a USRPHC at any time within the five-year period preceding the sale or other disposition (or the non-U.S. holder’s holding period, if shorter). Generally, a U.S. corporation is a USRPHC if the fair market value of its “United States real property interests,” as defined in the Internal Revenue Code of 1986, as amended, or the Code, and applicable Treasury Regulations, equals or exceeds 50% of the aggregate fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. Based on the current composition of our assets, we believe that we are not currently a USRPHC. However, because (i) the determination of whether we are a USRPHC at any time depends on the fair market value of our U.S. real property relative to the fair market value of other business assets at such time, and (ii) the determination as to whether certain of our assets, including our property, plant and equipment, constitute United States real property interests, as defined in the Code, may be uncertain, there can be no assurance that we will not become a USRPHC at any point in time in the future. If we were to become a USRPHC at any point during the shorter of (i) the five-year period preceding the sale or other disposition and (ii) the non-U.S. holder’s holding period, and either (1) our Class A common stock is not regularly traded on an established securities market during the calendar year in which the sale or disposition occurs or (2) the non-U.S. holder has owned or is deemed to have owned, at any time within the relevant period, more than 5% of our Class A common stock, the non-U.S. holder would be subject to tax on the net gain from the sale or other disposition under the regular graduated U.S. federal income tax rates applicable to U.S. persons and could, under certain circumstances, be subject to withholding at a 15% rate on the amount realized.

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Certain provisions of our amended and restated certificate of incorporation, amended and restated bylaws and Delaware law have anti-takeover effects that could limit our ability to engage in certain strategic transactions our board of directors believes would be in the best interests of stockholders.

Certain provisions of our amended and restated certificate of incorporation and amended and restated bylaws could discourage unsolicited takeover proposals that stockholders might consider to be in their best interests. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws includes provisions that, among other things:

•provide for a classified board of directors with staggered three-year terms (except that prior to the Trigger Date, our board of directors will consist of a single class of directors each serving one year terms);

•permit directors to be removed from the board of directors by our stockholders only for cause and with the affirmative vote of at least 75% of the combined voting power of our then-outstanding common stock (except that prior to the Trigger Date, directors may be removed by our stockholders with or without cause);

•do not permit cumulative voting in the election of directors, which would otherwise allow less than a majority of stockholders to elect director candidates;

•authorize the issuance of “blank check” preferred stock without any need for action by stockholders;

•limit the ability of stockholders to call special meetings of stockholders or to act by written consent in lieu of a meeting (except that prior to the Trigger Date, special meetings of stockholders may be called by stockholders holding a majority of the combined voting power of our then-outstanding common stock and shareholder actions may be taken by written consent in lieu of a meeting);

•require the affirmative vote of at least 75% of the combined voting power of our then-outstanding common stock, voting as a single class, to amend certain provisions of our certificate of incorporation (except that prior to the Trigger Date, such amendments require only the affirmative vote of a majority of the outstanding shares of common stock); and

•establish advance notice requirements for nominations for election to our board of directors or for proposing matters that may be acted on by stockholders at stockholder meetings; provided that, at any time when VG Partners and its permitted transferees beneficially own, in the aggregate, at least 5% of the combined voting power of our common stock, such advance notice procedure will not apply to VG Partners and its permitted transferees.

The foregoing factors, as well as the significant common stock ownership by VG Partners, could impede a merger, takeover, or other business combination or discourage a potential investor from making a tender offer for our common stock, which, under certain circumstances, could reduce the market value of our Class A common stock.

In addition, we have expressly elected not to be governed by the “Business Combination” provisions of Section 203 of the Delaware General Corporation Law, or the DGCL, until the earlier of the time at which (i) VG Partners and its permitted transferees no longer beneficially own at least 15% of the combined voting power of our then-outstanding common stock and (ii) our board of directors determines that we will be subject to Section 203 of the DGCL and gives written notice to VG Partners that VG Partners and its permitted transferees shall not be subject to Section 203 of the DGCL. Section 203 of the DGCL generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any interested stockholder for a period of three years following the date on which the stockholder became an interested stockholder. If at any time we become subject to the provisions of Section 203 of the DGCL, these provisions will prohibit large stockholders, in particular a stockholder owning 15% or more of the outstanding voting power, from consummating a merger or combination with our company from a three-year period beginning on the date of the transaction in which the stockholder acquired in excess of 15% of our outstanding voting stock, unless this stockholder receives board approval for the transaction or 662/3% of the combined voting power of our then-outstanding common stock not owned by the stockholder approve the merger or transaction. These provisions of Delaware law may have the effect of delaying,

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deferring or preventing a change in control, and may discourage bids for our Class A common stock at a premium over our market price.

We cannot guarantee that we will pay further dividends on our Class A common stock in the future and, consequently, your ability to achieve a return on your investment will depend on appreciation in the price of our Class A common stock.

While we have historically declared certain cash dividends and expect that we will declare and pay additional cash dividends on our common stock from time to time, we cannot guarantee that we will pay dividends on our Class A common stock in the future. The Company is a holding company and has no direct operations. All of our business operations are conducted through our subsidiaries. We cannot assure you that we will pay any dividend in the same amount or frequency as previous dividends, or at all, in the future. Any future dividend payments are within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, level of indebtedness, contractual restrictions with respect to payment of dividends, business opportunities, anticipated cash needs, provisions of applicable law and other factors that our board of directors may deem relevant. Consequently, your ability to achieve a return on any purchase of our Class A common stock could depend on the appreciation of our Class A common stock. Accordingly, you should not purchase shares of our Class A common stock with the expectation of receiving cash dividends.

Further, Delaware law requires that dividends be paid only out of “surplus,” which is defined as the fair market value of our net assets, minus our stated capital; or out of the current or the immediately preceding year’s earnings. In addition, our ability to pay dividends is subject to a range of restrictions and limitations set forth in the instruments governing our indebtedness and preferred equity.

If we, VG Partners or certain other stockholders sell shares of our Class A common stock or are perceived by the public markets as intending to sell them, the market price of our Class A common stock could decline.

The sale of substantial amounts of shares of our Class A common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our Class A common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell shares of our Class A common stock in the future at a time and at a price that we deem appropriate.

As of February 13, 2026, we had a total of 488,365,847 shares of our Class A common stock outstanding, of which 70,000,000 shares were sold in our IPO, and we had 224,879,858 outstanding stock options to purchase Class A common stock. All of the shares of our Class A common stock sold in our IPO are freely tradable without restriction or further registration under the Securities Act of 1933, as amended, or the Securities Act, by persons other than our “affiliates,” as that term is defined under Rule 144 of the Securities Act. All other shares of Class A common stock are eligible for resale in the public market, subject, in the case of shares held by our affiliates, to volume, manner of sale and other limitations under Rule 144.

In addition, as of February 13, 2026, an aggregate of 1,968,604,458 shares of our Class B common stock was outstanding, all of which was held by VG Partners. All such Class B shares of common stock are convertible into our Class A common stock on a one-to-one basis at any time at the option of the holder thereof. VG Partners continues to be considered an affiliate following our IPO, and accordingly shares of our Class A common stock issued upon conversion of our Class B common stock may not be sold in the absence of registration under the Securities Act unless an exemption from registration is available, including the exemptions contained in Rule 144.

VG Partners, as well as each other holder of shares of our common stock outstanding immediately prior to consummation of our IPO, will have the right, subject to certain exceptions and conditions, to require us to register their shares of Class A common stock under the Securities Act, and they will have the right to participate in future registrations of securities by us. Registration of any of these outstanding shares of common stock would result in such shares becoming freely tradable without compliance with Rule 144 upon effectiveness of the registration statement.

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We have also filed a registration statement on Form S-8 under the Securities Act to register shares of our Class A common stock issuable under our outstanding stock options to purchase Class A common stock and the shares of our Class A common stock reserved for issuance under the Venture Global, Inc. 2025 Omnibus Incentive Plan. Shares registered thereunder are available for sale in the open market. If such shares of Class A common stock are sold or it is perceived that they will be sold in the public market, the trading price of our Class A common stock could decline. These sales also could impede our ability to raise future capital.

You may be diluted by the future issuance of additional Class A common stock, including in connection with our incentive plans, acquisitions, conversion of our Class B common stock, or otherwise.

As of February 13, 2026, we had approximately 3.9 billion shares of Class A common stock authorized but unissued. Our amended and restated certificate of incorporation authorizes us to issue these shares of Class A common stock and options, rights, warrants and appreciation rights relating to Class A common stock for the consideration and on the terms and conditions established by our board of directors in its sole discretion, whether in connection with incentive plans, acquisitions or otherwise.

Additionally, shares of our Class B common stock are convertible into shares of our Class A common stock on a one-for-one basis at the option of the holder. Moreover, future transfers, except for certain permitted transfers described in our amended and restated certificate of incorporation, by VG Partners of shares of Class B common stock will generally result in those shares automatically converting into shares of Class A common stock on a one-for-one basis.

Any Class A common stock that we issue, including under our existing equity incentive plans or other equity incentive plans that we may adopt in the future and the conversion of Class B common stock into Class A common stock, would dilute holders of Class A common stock.

We cannot predict with certainty the size of future issuances of shares of our Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of shares of our common stock. Any such issuance could result in substantial dilution to our existing stockholders.

We may issue preferred stock whose terms could materially adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock with respect to dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our Class A common stock.

If our estimates or judgments relating to our critical accounting policies are based on assumptions that change or estimates that prove to be incorrect, our results of operations could be adversely affected, which could cause the price of our Class A common stock to decline.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in our financial statements and the accompanying notes thereto. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets, liabilities, equity, revenue and expenses that are not readily apparent from other sources. It is possible that interpretation, industry practice and guidance involving our estimates and assumptions may evolve or change over

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time. If our assumptions change, or if actual circumstances differ from our assumptions, our results of operations may be adversely affected, which could cause the price of our Class A common stock to decline.

As a result of being a public company, we are obligated to develop and maintain proper and effective internal control over financial reporting, and any failure to maintain the adequacy of our internal control may adversely affect investor confidence in our company and, as a result, the value of our Class A common stock.

As a public company, we are required to commit significant resources and management time and attention to the requirements of being a public company, which causes us to incur significant legal, accounting and other expenses that we had not incurred as a private company, including costs associated with public company reporting requirements. We incur costs associated with the Securities Exchange Act of 1934, as amended, or the Exchange Act, the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, the Dodd-Frank Wall Street Reform and Protection Act, and related rules implemented by the Securities and Exchange Commission, or the SEC, and the NYSE, and compliance with these requirements places significant demands on our legal, accounting and finance staff and on our accounting, financial and information systems.

We are required, pursuant to Section 404 of the Sarbanes-Oxley Act, to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting for the fiscal year ending December 31, 2025. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. In addition, our independent registered public accounting firm will be required to attest to the effectiveness of our internal control over financial reporting in our Form 10-K required to be filed with the SEC for the fiscal year ending December 31, 2026. Our compliance with Section 404 of the Sarbanes-Oxley Act requires that we incur substantial expenses and expend significant management efforts. During 2025, we established an internal audit function, lead by a Chief Audit Executive, to compile the system and process documentation necessary to perform the evaluation needed to comply with Section 404 of the Sarbanes-Oxley Act.

During the evaluation and testing process of our internal controls, if we identify one or more material weaknesses in our internal control over financial reporting, we will be unable to certify that our internal control over financial reporting are effective. We cannot assure you that there will not be material weaknesses or significant deficiencies in our internal control over financial reporting in the future. Any failure to maintain internal control over financial reporting could severely inhibit our ability to accurately report our financial condition or results of operations. If we are unable to conclude that our internal control over financial reporting are effective, or if our independent registered public accounting firm determines we have a material weakness or significant deficiency in our internal control over financial reporting, we could lose investor confidence in the accuracy and completeness of our financial reports, the market price of our Class A common stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities. Failure to remedy any material weakness in our internal control over financial reporting, or to implement or maintain other effective control systems required of public companies, could also restrict our future access to the capital markets.

We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for exemptions from certain corporate governance requirements. If we rely on such exemptions in the future, you will not have the same protections afforded to stockholders of companies that are subject to such requirements.

VG Partners controls a majority of the voting power of our outstanding common stock, and as a result, we are a “controlled company” within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

•a majority of the board of directors consist of independent directors;

•the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

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•the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

•there be an annual performance evaluation of the nominating and corporate governance and compensation committees.

Consistent with these exemptions, we do not have an independent compensation committee or an independent nominating and corporate governance committee. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware or the federal district courts of the United States of America, as applicable, as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which limits our stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or the Company’s directors, officers or other employees.

Our amended and restated certificate of incorporation provides that, unless we consent to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for: (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a breach of fiduciary duty owed by any current or former director, officer, stockholder or employee of the Company to the Company or our stockholders; (iii) any action asserting a claim against us arising under the Delaware General Corporation Law, or the DGCL, our certificate of incorporation or our bylaws or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware; or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine.

These provisions do not apply to suits brought to enforce a duty or liability created by the Exchange Act. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain such claims. To prevent having to litigate claims in multiple jurisdictions and the threat of inconsistent or contrary rulings by different courts, among other considerations, our amended and restated certificate of incorporation further provides that the federal district courts of the United States of America are the exclusive forum for resolving any complaint asserting a cause or causes of action arising under the Securities Act, including all causes of action asserted against any defendant to such complaint. While the Delaware courts have determined that such choice of forum provisions are facially valid, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in the exclusive forum provisions and there can be no assurance that these provisions will be enforced by a court in those other jurisdictions. In this regard, stockholders may not be deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder, including Section 22 of the Securities Act.

Any person or entity purchasing or otherwise acquiring any interest in any shares of our capital stock shall be deemed to have notice of and to have consented to the forum provision in our amended and restated certificate of incorporation. This choice-of-forum provision may limit a stockholder’s ability to bring a claim in a different judicial forum, including one that it may find favorable or convenient for a specified class of disputes with the Company or the Company’s directors, officers, other stockholders or employees, which may discourage such lawsuits. Alternatively, if a court were to find this provision of our amended and restated certificate of incorporation inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors.

General Risk Factors

Global economic conditions, including inflation and supply chain disruptions, could continue to adversely affect our operations.

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General global economic downturns and macroeconomic trends, including heightened inflation, capital market volatility, interest rate and currency rate fluctuations, and economic slowdown or recession, may result in unfavorable conditions that could negatively affect demand for our products and exacerbate some of the other risks that affect our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. Both domestic and international markets experienced significant inflationary pressures in fiscal years 2022 and 2023 and to combat such inflation, the Federal Reserve in the U.S. and other central banks in various countries raised interest rates in response. While the Federal Reserve began lowering interest rates in 2024 as inflation decreased, to the extent that inflationary pressures arise in the future, further interest rate increases or other government actions taken to reduce inflation could result in recessionary pressures in many parts of the world. Furthermore, currency exchange rates have been especially volatile in the recent past, and these currency fluctuations have affected, and may continue to affect, the reported value of our assets and liabilities, as well as our cash flows.

We have also experienced significant challenges in our global supply chain, including shortages in supply of materials and equipment to complete construction of our projects. While to date, we have been able to manage the challenges associated with these delays and shortages without significant disruption to our business, no assurance can be given that these efforts will continue to be successful. In addition, the deterioration of conditions in global credit markets may limit our ability to obtain, or may increase the cost of, external financing to fund our operations and capital expenditures on terms favorable to us, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us, when we require it, we will have to significantly reduce our spending, delay or cancel construction of our projects or substantially change our corporate structure, and we might not have sufficient resources to conduct or support our business as projected, which would have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects. See —Risks Relating to Our Projects and Other Assets—We will require significant additional capital to construct and complete certain of our projects, and we may not be able to secure such financing on time with acceptable terms, or at all, which could cause delays in our construction, lead to inadequate liquidity and increase overall costs.

Developments related to the ongoing war between Russia and Ukraine and the ongoing conflicts in the Middle East, as well as geopolitical instability in Venezuela, could adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Russia is one of the main players in the global oil and gas markets. Accordingly, any events that can impair or enhance its ability to compete in such markets are likely to have an impact on the industry in which we operate and the operations of our projects. Since the beginning of Russia’s invasion of Ukraine, sanctions have been imposed by Ukraine’s allies that seek to limit Russia’s ability to profit from oil and gas exports, and certain retaliatory measures have been taken by Russia in response (such as the ban on sales to certain countries). Additionally, there have been publicized threats to increase hacking activity against the critical infrastructure of any nation or organization that retaliates against Russia for its invasion.

The Middle East remains a critical region for global energy production and ongoing and escalating conflicts in the region—including armed hostilities involving Israel, Gaza, Iran and Iran-aligned groups in Lebanon and Gaza, including Hamas and Hezbollah—could adversely affect global energy markets. Such conflicts have resulted in, and could continue to result in, supply disruptions, damage to energy infrastructure, increased shipping and insurance costs, delays or rerouting of oil and gas cargos, heightened security risks, and increased volatility in oil and gas prices. Any material escalation or regional expansion of these conflicts could further disrupt global energy supply chains and trade flows and adversely affect market conditions relevant to our business.

Venezuela, a country estimated to hold the largest proven oil reserves in the world, has been subject to significant political, economic and social instability resulting from decades of underinvestment, infrastructure deterioration and the imposition of extensive international sanctions on its state-owned oil company. Recent events in Venezuela have raised the prospect of a potential increase in Venezuelan hydrocarbon production over the medium- to long-term. If such increased output were to materialize, the increase in oil supply could exert downward

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pressure on oil and other benchmark energy prices and alter regional supply dynamics, which in turn could affect global natural gas and LNG demand and prices.

In addition, the disruptions caused by the invasion of Ukraine, instability in the Middle East and Venezuela, and other geopolitical events have included, and may continue to include, political, social, and economic disruptions and uncertainties. Moreover, continued or escalating geopolitical conflicts, including those involving Russia, Ukraine, the Middle East and Venezuela, could contribute to sustained periods of elevated commodity price volatility (including material increases in certain commodity prices), shifting global supply patterns, reduced liquidity in energy markets and increased risk premiums in financial and commodity markets. Any prolonged, intensified or expanded conflict could materially disrupt international energy trade flows, constrain access to or the cost of imported energy and feedstock supplies, negatively impact demand for LNG and other energy commodities, and materially and adversely affect our competitive position, financial condition, results of operations and future growth prospects.

Terrorist attacks, including cyberterrorism, or military campaigns may adversely impact our business.

An act of terrorism, including an act of cyberterrorism, or military incident affecting LNG facilities, including our projects, may result in delays in construction, which could increase the cost of completion of our projects beyond the amounts that we have estimated. See —Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors. An act of terrorism, including an act of cyberterrorism, incident may also result in temporary or permanent closure of any of our projects, which could increase our costs and decrease our cash flows, depending on the duration and timing of the closure. Our operations could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism, including cyberterrorism, and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our business and our customers, including their ability to satisfy their obligations to us under our commercial agreements. Instability in the financial markets as a result of an act of terrorism, including an act of cyberterrorism, war, earthquakes and other natural or man-made disasters, pandemics, credit crises, recessions or other factors could increase the cost of insurance coverage and could also result in a significant decline in the U.S. economy and could also materially adversely affect our ability to raise capital. The continuation of these developments may subject our construction and our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Changes in tax laws or tax rulings, or the examination of our tax positions, could materially affect our financial condition and results of operations.

We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including those with retroactive effect, could affect our tax obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. Our existing corporate structure and intercompany arrangements have been implemented in a manner we believe is in compliance with current prevailing tax laws. In addition, the taxing authorities in the United States and other jurisdictions where we do business regularly examine income and other tax returns and we expect that they may examine our income and other tax returns. The ultimate outcome of these examinations cannot be predicted with certainty. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

We face risks related to the uncertainty regarding the future of international trade agreements and the United States’ position on international trade.

Certain policies and statements of the current Trump administration have given rise to uncertainty regarding the future of international trade agreements and the United States’ position on international trade. For example, in April 2025, the Trump administration announced broad reciprocal tariffs on imports from all countries. This

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included a 10% baseline tariff and higher country-specific tariffs, and resulted in some countries announcing additional retaliatory tariffs, or plans for retaliatory tariffs. While the U.S. Supreme Court issued a ruling against the

validity of such tariffs in February 2026, the Trump administration has announced the imposition of a new 15% baseline tariff under other legal authority and there is ongoing uncertainty in connection with tariff policies. The imposition and or threat of tariffs by the United States has in the past, and may continue to in the future, result in retaliatory tariffs imposed on U.S. businesses from any countries affected by such tariffs. Additionally, the imposition of retaliatory tariffs by any nation against the U.S. could have a material adverse effect on trade between the U.S. and other nations, as well as on the cost of goods for U.S. companies and consumers. The impact of any such tariffs remains uncertain and accordingly is not reﬂected in our current project cost estimates. However, the impositions of such tariffs could negatively affect demand for our products and our project cost estimates, particularly construction costs that may relate to foreign-sourced materials such as steel and aluminum, and also exacerbate some of the other risks that affect our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity.

We also face potential exposure to evolving U.S. tariff standards, and potential retaliatory international tariffs that may be imposed by other countries in response to U.S. tariffs, primarily on LNG exports and construction-related materials, systems, piping and commodities (e.g. cement, copper, nickel and steel). China’s decision to continue to implement a 15% tariff on coal and LNG products in response to U.S. tariff initiatives may potentially impact our ability to sell commissioning and short-term LNG cargos to China. In addition, given the rapidly evolving and volatile tariff landscape, we cannot anticipate the breadth of potential tariffs that may be announced and/or implemented on internationally sourced components and commodities used to construct our LNG facilities. As a result, the impact of any such tariffs remains uncertain and accordingly is not reﬂected in our current project cost estimates. However, the imposition of any such tariffs could negatively affect demand for our products and our project cost estimates, and also exacerbate some of the other risks that affect our business, contracts, financial condition, operating results, cash ﬂow, financing requirements, and liquidity.

As of December 31, 2025, we had entered into post-COD SPAs for an aggregate of 9.5 mtpa with Chinese customers across all of our projects. Any future changes to the United States’ trade relationship with China or other major LNG importing nations, including through the imposition of further tariffs, could have an adverse impact on such SPAs and our ability to market the remaining production capacity of our projects, by reducing demand from such customers for U.S. LNG exports.

Moreover, various bilateral trade negotiations are ongoing and additional negotiations may take place, any of which could result in further changes to country-specific trade policies and tariffs. For example, the United States announced a framework trade deal in July 2025 pursuant to which certain European Union goods entering the United States would be subject to a 15% tariff, and the European Union would commit to make $750 billion of strategic energy purchases, covering oil, LNG and nuclear technology, during President Trump’s term in office. However, in February 2026, the European Parliament halted the ratification process in light of the U.S. Supreme Court ruling against the validity of tariffs and the subsequent tariffs announced by the Trump administration. There can be no assurance as to the outcome of any ongoing or additional negotiations, or as to the final terms of the trade deal with the European Union. The European Union is the largest provider of foreign-sourced equipment for our LNG construction projects by dollar value. Global economic uncertainty and any related reduction in economic activity or capital investment may slow growth in global GDP or lead to global recession. Accordingly, these tariffs and any retaliatory actions from other countries could have a material impact on our financial condition, results of operations and/or cash flows through reduced demand and competitiveness for both our long-term and short-term contract sales in countries that may be affected by those policies, and increased project costs for future imported equipment and materials.

The uncertainty regarding the policies of the current Trump administration with respect to the future of trade partnerships and relations, including the possibility of additional or increased tariffs, may reduce our competitiveness in countries that may be affected by those policies, such as China and the European Union, whether or not the current Trump administration ultimately takes any additional actions. Any of these factors could adversely affect our ability to market the remaining production capacity of our projects, which could have a material

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adverse effect on the viability of our projects and on our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

Our ability to use our net operating losses to offset future taxable income may be subject to certain limitations.

As of December 31, 2025, we have accumulated federal and foreign net operating loss, or NOL, carryforwards of $10.0 billion and $25 million, respectively, with an indefinite carryforward period. We additionally had accumulated state net operating loss carryforwards of approximately $3.4 billion, of which $42 million will expire by 2037. Under the current tax law, federal NOLs incurred in taxable years beginning after December 31, 2017, can be carried forward indefinitely, but the deductibility of such federal NOLs in taxable years beginning after December 31, 2020 is limited to 80% of taxable income. These federal and state NOLs may be available to offset income tax liabilities in the future. In addition, we may generate additional NOLs in future years. NOLs may be limited by separate return limitation year, or SRLY, rules. These rules generally limit the use of NOL carryforwards to the amount of taxable income that the NOL producing entity contributes to consolidated taxable income during the year. Of the federal NOL carryforward amount stated earlier, $23 million is currently subject to the SRLY rules. NOLs subject to the SRLY limitations may also be subject to Section 382 limitations described below.

In general, under Section 382 of the Code, or Section 382, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change NOLs to offset future taxable income. For this purpose, an ownership change generally means a more than 50 percentage point change in the ownership of a corporation by one or more shareholders or specified groups of shareholders, each of which owns 5% or more of the corporation (determined after the application of certain attribution and grouping rules) over a three-year period. Although we do not believe that any of our NOLs are currently subject to limitation under Section 382, future changes in our stock ownership could result in an ownership change under Section 382, which could limit our ability to use our existing or future NOLs to offset future taxable income.

The outbreak of any infectious diseases or other illness could adversely impact our business, contracts, financial condition, operating results, cash flow, financing requirements, liquidity and prospects.

We are subject to risks related to outbreaks of infectious diseases. The extent to which an outbreak of an infectious disease or other illness could impact our business, operations and financial results depends on numerous factors that we cannot accurately predict, including: the duration and scope of any infectious disease; governmental, business and individuals’ actions taken in response to any infectious disease and the associated impact on economic activity; the effect on the level of global demand for natural gas; geopolitical developments in the oil and gas markets; our ability to procure materials and services from third parties that are necessary for the operation of our business; the effect on the labor market, including worker shortages or related to supply chain disruptions; our ability to provide our services, including as a result of travel restrictions on our employees and employees of third parties that we utilize in connection with our services; the potential for key executives or employees to fall ill; and the ability of our customers to pay for our services if their businesses suffer as a result of any infectious disease.

We cannot estimate the magnitude and duration of potential social, economic and labor instability as a direct result of any infectious disease or pandemic. Should any of these potential impacts continue for an extended period of time, it will have a negative impact on the demand for our services and a material adverse effect on our financial position and results of operations. Moreover, the foregoing factors may also have the effect of heightening some of the other risk factors described herein.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

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Cybersecurity Risk Management

Cybersecurity risk management is a critical priority for our Company, and we recognize the increasing sophistication and prevalence of cyber threats globally. We face ongoing risks related to cyber-attacks, data breaches, and system disruptions, which could materially impact our operations, financial results, and reputation. These risks encompass a broad spectrum, including potential disruptions to our critical energy infrastructure, compromise of confidential or sensitive operational and commercial data, theft of intellectual property, and financial losses resulting from business interruption, remediation costs, and regulatory penalties. Our cybersecurity program is designed to align with industry-leading standards, including the widely recognized NIST Cybersecurity Framework (CSF), and provides a framework for handling cybersecurity threats and incidents, including threats and incidents associated with the use of services provided by third-party service providers. This framework guides our approach to cybersecurity risk management through five core principles: Identify, Protect, Detect, Respond, and Recover, which enable what we believe is a comprehensive and proactive security posture. Our cybersecurity program is comprised of policies, procedures, controls, and tools designed to mitigate cybersecurity risks. We maintain a risk assessment process which includes steps for identifying cybersecurity threats, assessing the severity and impact, identifying the source of a cybersecurity threat, including whether the cybersecurity threat is associated with a third-party service provider, implementing cybersecurity countermeasures and mitigation strategies and informing management and our board of directors of material cybersecurity threats and incidents. This program includes preventative controls, continuous monitoring, incident detection and response capabilities, and regular security assessments and updates. Our cybersecurity team also engages third-party security experts for risk assessment and system enhancements.

We are committed to complying with all applicable cybersecurity regulations, including those relevant to the operation of US LNG export terminals and natural gas pipelines. Our facilities and maritime operations are subject to the Maritime Transportation Security Act, and we are dedicated to meeting its applicable cybersecurity-related requirements as enforced by the US Coast Guard and relevant guidance from agencies such as the Cybersecurity and Infrastructure Security Agency. We are committed to continuously enhancing our cybersecurity defenses and incident response plans to adapt to the evolving threat landscape and protect our assets and stakeholders. Given the nature of our operations, a particular area of focus is the security of our Operational Technology and Industrial Control Systems, which are essential for the safe and continuous operation of our liquefaction plants, terminals, and related infrastructure. Protecting these systems from cybersecurity threats is paramount to prevent operational disruptions, ensure safety, and maintain the reliability of our energy delivery.

Our board of directors has overall oversight responsibility for our risk management, and, following our IPO, delegates cybersecurity risk management oversight to the audit committee. The audit committee is responsible for ensuring that management has processes in place designed to identify and evaluate cybersecurity risks to which we are exposed and implement processes and programs to manage cybersecurity risks and mitigate cybersecurity incidents. The audit committee reports material cybersecurity risks to our full board of directors. Cybersecurity governance is overseen by senior management, which is responsible for identifying, considering and assessing material cybersecurity risks on an ongoing basis, establishing processes to ensure that such potential cybersecurity risk exposures are monitored, putting in place appropriate mitigation measures and maintaining cybersecurity programs.

Leadership for our cybersecurity program is provided by our Chief Information Officer, or CIO, who receives reports from our cybersecurity team and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents. Our CIO is a seasoned executive with over 25 years of experience in Information Technology, including 18 years in cybersecurity leadership roles specifically within the energy industry. The CIO's expertise is further underscored by prior service on the American Gas Association's Distribution Natural Gas Information Sharing and Analysis Center and as a former President of Oregon's InfraGard chapter, a partnership between the FBI and the private sector. Notably, the CIO also serves as our Chief Information Security Officer and is supported by a cybersecurity team with many years of experience led by a Vice President of Cybersecurity. Management, including the Chief Financial Officer and CIO, will update the audit committee on our cybersecurity programs, material cybersecurity risks, program assessments and mitigation strategies. The CIO will provide periodic cybersecurity reports that cover these topics and industry developments.

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Despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced an undetected cybersecurity incident. For more information about these risks, please see Item 1A.—Risk Factors—Risks Relating to Intellectual Property, Data Privacy and Cybersecurity—Hostile cyber intrusions, or other issues with our information technology, could severely impair our operations, lead to the disclosure of confidential information, damage our reputation and otherwise have a material adverse effect on our business of this Form 10-K.

ITEM 2. PROPERTIES

In the aggregate, as of December 31, 2025, we owned, leased or had an option to lease or purchase over 6,900 acres of land on the United States Gulf Coast, upon which we are developing our liquefaction and export projects.

For each of our Calcasieu, Plaquemines, CP2, and CP3 projects, we entered into various 30-year leases, which may be extended at our option for up to four additional 10-year terms, up to 70 years in the aggregate. Our Calcasieu project benefits from leases covering approximately 430 acres of land for our project site, and approximately 230 additional acres of ancillary land supporting the project. Our Plaquemines Project benefits from leases covering approximately 630 acres of land for our project site, and approximately 1,820 additional acres of ancillary land supporting the project. We also entered into lease option agreements for approximately 1,100 acres of adjacent land that can be used for the Plaquemines Expansion Project, under substantially similar terms as our existing leases for the Plaquemines Project. Our CP2 project benefits from leases covering approximately 1,300 acres of land for our project site, and approximately 570 additional acres of ancillary land supporting the project. Finally, our CP3 project benefits from leases covering approximately 840 acres of land for our CP3 project site.

In addition, we also own and lease various surface site locations in support of the construction and development of interstate and intrastate pipelines to deliver natural gas into our LNG facilities.

We own the office space in Arlington, VA where our principal executive offices are located. In addition, we lease office space in Houston, TX; Singapore; London, England; and Tokyo, Japan. These office leases expire or become subject to renewal clauses at various dates.

ITEM 3. LEGAL PROCEEDINGS

We are involved, and in the future may become involved, in various claims, lawsuits, administrative, regulatory and other proceedings incidental to the ordinary course of our business from time to time. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

We are required to assess the likelihood of any adverse judgments or outcomes related to these legal contingencies, as well as potential ranges of probable or reasonably possible losses. We accrue for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The determination of the amount of any losses to be recorded or disclosed as a result of these contingencies is based on a careful analysis of each individual exposure with, in some cases, the assistance of outside legal counsel. There can be no assurance that any accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.

Securities Litigation

On February 17, 2025, a putative securities class action complaint naming Venture Global, our directors and certain of our officers was filed in the U.S. District Court for the Southern District of New York. The complaint asserts claims under Sections 11 and 15 of the Securities Act on behalf of a putative class of all persons and entities who purchased or otherwise acquired our Class A common stock pursuant and/or traceable to the registration statement for the IPO. It contends that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedly false or misleading and seeks

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unspecified damages on behalf of the putative class. The complaint was voluntarily dismissed with prejudice on April 24, 2025.

Further, on April 15, 2025, a putative securities class action complaint naming Venture Global, our directors and certain of our officers and our underwriters, as well as Venture Global Partners II, LLC, was filed in the U.S. District Court for the Eastern District of Virginia and was subsequently transferred to the Southern District of New York. The complaint, as subsequently amended on September 15, 2025 and December 5, 2025, asserts claims under Sections 11, 12, and 15 of the Securities Act on behalf of a putative class of all persons and entities who purchased or otherwise acquired our Class A common stock pursuant and/or traceable to the registration statement for the IPO. It contends that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedly false or misleading and seeks unspecified damages on behalf of the putative class. The Company believes these claims are without merit and intends to defend itself vigorously. On January 28, 2026, we filed a motion to dismiss the amended securities class action complaint.

Further, on May 7, 2025, a putative shareholder derivative action complaint naming Venture Global, our directors, certain of our officers and certain of our underwriters was filed in the U.S. District Court for the Eastern District of Virginia and was subsequently transferred to the Southern District of New York. The complaint contends that certain statements made by the Company and certain of its officers and directors in the registration statement and prospectus for the IPO were allegedly false or misleading. The complaint asserts breaches of fiduciary duties, gross mismanagement, waste of corporate assets, unjust enrichment, and aiding and abetting, and seeks unspecified damages for such breaches. Three additional putative shareholder derivative action complaints naming Venture Global, our directors, certain of our officers and certain of our underwriters, were filed in the U.S. District Court for the Southern District of New York on June 10, 2025, June 27, 2025 and June 30, 2025, respectively. Each of these three complaints contains substantially similar allegations to those described above. All four shareholder derivative action complaints have been stayed pending resolution of our motion to dismiss the amended securities class action complaint that was filed on January 28 2026. The Company believes all of the foregoing claims are without merit and intends to defend itself vigorously.

Arbitration Proceedings

In May 2023, Shell NA LNG LLC (“Shell”) submitted a request for arbitration to the ICC, in accordance with the dispute resolution procedures of its post-COD SPA, asserting, among other claims, that the Calcasieu Project was delayed in achieving COD under the relevant post-COD SPA. On August 12, 2025, the ICC issued a partial final award in the Shell arbitration proceeding. Pursuant to the award, it was determined that VGCP had not breached its obligations under the post-COD SPA relating to the Calcasieu Project with Shell and, consequently, the tribunal determined that VGCP had no liability to Shell for its claims under the arbitration proceedings. Among other remedies, Shell was seeking damages of approximately $1.7 billion. On November 11, 2025, the ICC issued a final award requiring Shell to pay certain attorneys’ fees and costs to VGCP. On November 10, 2025, Shell filed a petition with the New York Supreme Court, Commercial Division, seeking to vacate the arbitral award. The proceedings to consider Shell’s petition are pending.

In May 2023, one additional long-term customer of the Calcasieu Project submitted a request for arbitration to the London Court of International Arbitration, in accordance with the dispute resolution procedures of its post-COD SPA, asserting, among other claims, that the Calcasieu Project is delayed in achieving COD under the post-COD SPA. The remedies sought by such long-term customer include damages of approximately $1.5 billion (which is potentially subject to increase with the passage of time), rather than the termination of the post-COD SPA. The hearing for such arbitration proceeding occurred in October 2024 and an award is anticipated in 2026.

In August 2023, one additional long-term customer of the Calcasieu Project submitted a request for arbitration to the ICC in accordance with the dispute resolution procedures of its post-COD SPA, asserting, among other claims, that the Calcasieu Project is delayed in achieving COD under the relevant post-COD SPA. Additionally, this customer has disputed that the delay to COD constitutes a force majeure event in the context of their arbitration proceedings. The customer is currently seeking remedies in excess of $400 million. The hearing for this arbitration proceeding took place in June 2025 and an award is anticipated in 2026.

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In March 2024, a mid-term customer of the Calcasieu Project submitted a request for arbitration to the ICC in accordance with the dispute resolution procedures of the post-COD SPA between us and that customer. On September 2, 2025, VGCP entered into a settlement agreement in respect of previously disclosed arbitration proceedings with another customer regarding its post-COD SPA relating to the Calcasieu Project. Among other remedies, this customer was seeking damages of approximately $200 million. The settlement resolved the arbitration in its entirety and had no material impact on Venture Global.

On October 8, 2025, the ICC informed VGCP that a partial final award had been issued in the previously disclosed arbitration proceedings with BP regarding LNG sales from the Calcasieu Project under the post-COD SPA entered into by VGCP and BP. The award issued by the arbitration tribunal found that VGCP had breached its obligations to declare COD of the Calcasieu Project in a timely manner and act as a “Reasonable and Prudent Operator” pursuant to the post-COD SPA, along with certain other obligations. Remedies were not addressed in the partial final award and will be determined in a separate damages hearing, which has not been scheduled but is anticipated to occur in 2026 or 2027. A final award is expected to be issued following the damages portion of the hearing. Based on the terms of the award, the Company does not anticipate that the final award will be subject to the seller aggregate liability limitation in the BP post-COD SPA. The remedies sought by BP include damages ranging from $3.7 billion to potentially in excess of $6.0 billion, as well as interest, costs and attorneys’ fees. We believe BP’s theory and calculations of damages are without merit and that the magnitude of damages sought by BP is not recoverable under the express terms of the post-COD SPA, which include express limits on the tribunal’s jurisdictional authority, although there can be no assurance as to the outcome of the damages portion of the hearing.

In August 2023, Repsol LNG Holding, S.A. (“Repsol”) submitted a request for arbitration to the ICC in accordance with the dispute-resolution procedures of its post-COD SPA, asserting, among other claims, that the Calcasieu Project was delayed in achieving COD under the relevant post-COD SPA. Additionally, Repsol disputed that the delay to COD constitutes a force majeure event in the context of the arbitration proceedings. Among other remedies, Repsol sought damages in excess of $400 million. On January 15, 2026, the ICC issued a final award in that proceeding. Pursuant to the award, it was determined that VGCP had not breached its obligations under the post-COD SPA relating to the Calcasieu Project with Repsol and, consequently, the tribunal denied all of Repsol's claims in full. The award also required Repsol to pay certain attorneys’ fees and arbitration costs to VGCP.

In December 2023, one additional long-term customer of the Calcasieu Project submitted a request for arbitration to the ICC in accordance with the dispute resolution procedures of the post-COD SPA between us and that customer, asserting, among other claims, that the Calcasieu Project was delayed in achieving COD under the relevant post-COD SPA. The remedies sought by this customer include damages in excess of $2.0 billion.

We disagree with the assertions and legal claims in each of the ongoing requests for arbitration and the legal proceedings seeking to vacate one such arbitral award, and the Calcasieu Project is defending the remaining arbitration proceedings and such legal proceedings. We believe that any damages award in such arbitration proceedings should be subject to the relevant seller aggregate liability cap under the relevant post-COD SPA (other than in in the case of the arbitration award relating to the BP post-COD SPA), which aggregate to $595 million across the relevant post-COD SPAs. However, these customers are also disputing whether the liability limitations in the Calcasieu Project's post-COD SPAs are applicable, and therefore are claiming damages, including amounts in excess of the liability limitations. If the Calcasieu Project is unsuccessful in defending against these claims, the amounts it could be required to pay could be substantial, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects, as well as the trading price of our

Class A common stock.

Other Matters

Certain of our former employees have filed proceedings, including in Virginia federal court, seeking aggregate damages ranging between $181 million and $280 million in the aggregate with respect to alleged breaches of certain stock option grant agreements and related matters.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our Class A common stock has traded on the New York Stock Exchange under the symbol “VG” since January 24, 2025. Prior to this date, there was no public trading market for our Class A common stock. There is no public trading market for our Class B common stock.

Holders

As of February 13, 2026, we had approximately 488,365,847 shares of Class A common stock outstanding held by two record owners. As of February 13, 2026, there was one holder of record of our Class B common stock. This does not include the number of stockholders that hold shares in “street-name” through banks or broker-dealers.

Dividend Policy

Our Second Amended and Restated Certificate of Incorporation authorizes Class A common stock and Class B common stock and provides that holders of our Class A common stock and holders of our Class B common stock will be treated equally and ratably on a per share basis with respect to any dividends (unless different treatment of the shares of a class is approved by the affirmative vote of the holders of a majority of the outstanding shares of the applicable class of common stock treated adversely, voting separately as a class).

We currently expect that we will declare and pay additional cash dividends on our common stock from time to time. However, we cannot assure you that we will pay any dividend in the same amount or frequency as previous dividends, or at all, in the future. Any future dividend payments are within the absolute discretion of our board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, financial condition, level of indebtedness, preferred equity obligations, contractual restrictions with respect to payment of dividends, general economic business conditions, industry practice, business opportunities, anticipated cash needs, provisions of applicable law and other factors that our board of directors may deem relevant. Consequently, your ability to achieve a return on your investment could depend on the appreciation of our Class A common stock. Further, Delaware law requires that dividends be paid only out of “surplus,” which is defined as the fair market value of our net assets, minus our stated capital; or out of the current or the immediately preceding year’s earnings. In addition, our ability to pay dividends is subject to a range of restrictions and limitations set forth in the instruments governing our indebtedness and preferred equity. For more details, see Item 7.—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources, Item 1A.—Risk Factors—Risks Relating to Our Indebtedness and Financing—Certain of our debt agreements impose significant operating and financial restrictions on our subsidiaries, and the preferred equity of our subsidiaries also gives the holders certain consent rights, all of which may prevent us from capitalizing on business opportunities or paying dividends to the Company and Item 1A.—Risk Factors—Risks Relating to Our Indebtedness and Financing—As a holding company, the Company depends on the ability of its subsidiaries to transfer funds to it to meet its obligations of this Form 10-K.

Recent Sales of Unregistered Securities

None.

Use of Proceeds from Registered Securities

On January 27, 2025, we closed our IPO in which we issued and sold 70 million shares of Class A common stock. The shares sold in our IPO were registered under the Securities Act pursuant to our Registration Statement Form S-1, as amended (File No. 333-283964) which was declared effective by the SEC on January 23, 2025. Our

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shares of Class A common stock were sold at an initial public offering price of $25.00 per share, which generated net proceeds of approximately $1.7 billion after deducting underwriting discounts and commissions of $70 million. We estimated that we incurred offering expenses of approximately $10 million.

The proceeds from our IPO (net of underwriting discounts) were used to support the continued growth and development of our business. This includes, but is not limited to, expenditures for pre-FID development, procurement and construction costs at our CP2 Project, costs for other future projects and bolt-on expansion projects, milestone payments for our LNG tankers, pipeline development costs, and for other general corporate purposes. There were no material changes to our planned use of net proceeds from our IPO as described under the heading “Use of Proceeds” in our final prospectus, filed with the SEC on January 23, 2025 pursuant to Rule 424(b)(4) relating to our Registration Statement.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

None.

ITEM 6. [RESERVED]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and the accompanying notes thereto, included in Item 8.—Financial Statements and Supplementary Data of this Form 10-K. In addition to historical consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs that involve significant risks and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to those differences include those discussed below and elsewhere in Item 1A.—Risk Factors and Cautionary Statement Regarding Forward-Looking Statements of this Form 10-K. Except for per MMBtu amounts, or as otherwise specified, dollar amounts presented within tables are stated in millions.

During the year ended December 31, 2025, the Company's sales and shipping business met the criteria to be a reportable segment. Prior to the year ended December 31, 2025, sales and shipping was not quantitatively material for reporting purposes and was combined with corporate activities as corporate, other and eliminations. Prior period presentations included within Item 7. ––Management's discussion and Analysis of Financial Condition and Results of Operations of this form 10-K has been recast to conform to the current segment reporting structure.

For discussion of the Company's year ended December 31, 2024 compared to the year ended December 31, 2023, refer to Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Form 10-K filed with the SEC on March 6, 2025.

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Executive Summary

Our Financial Results.


	Years ended December 31,
		2025		2024

Income from operations		$	5,156	$	1,763

LNG volumes exported
Cargos		380		141
TBtu		1,415.4		508.4

LNG volumes sold (TBtu)		1,408.8		500.6
Weighted average price of LNG volumes sold (per MMBtu)
Liquefaction fee (1)		$	5.87	$	7.28
Commodity fee		3.93		2.61
Weighted average price of LNG volumes sold		$	9.80	$	9.89

____________

(1) Includes sales prices indexed to foreign gas markets, exclusive of an implied commodity fee, and fixed liquefaction fees.

Our income from operations for the year ended December 31, 2025 increased compared to the prior year primarily due to higher sales volumes at our Plaquemines Project from the commencement of LNG production in December 2024 and continued ramp up of LNG production during 2025. This was partially offset by lower weighted average LNG sales prices at our Calcasieu Project due to the commencement of LNG sales under its post-COD SPAs and the higher cost of feed gas.

Our LNG Projects

Calcasieu Project. Our initial LNG export facility declared COD and commenced the sale of LNG to its customers under our post-COD SPAs on April 15, 2025. Prior to COD, the Calcasieu Project sold LNG under LNG Commissioning Sales Agreements.


		Calcasieu Project
	Years ended December 31,
		2025		2024

LNG volumes exported
Cargos		146		140
TBtu		539.3		504.5

LNG volumes sold (TBtu)		538.5		501.6
Weighted average price of LNG volumes sold (per MMBtu)
Fixed liquefaction fee		$	3.63	$	7.15
Commodity fee		3.95		2.61
Weighted average price of LNG volumes sold		$	7.58	$	9.76

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Plaquemines Project. Production and sales of LNG from our second LNG export facility increased during the period while physical construction and the commissioning program of the project continued to advance. During the year ended December 31, 2025, we incurred $3.9 billion of project costs, the majority of which were capitalized, and we placed an additional $13.4 billion of assets in service in accordance with the applicable accounting guidance.


		Plaquemines Project
	Years ended December 31,
		2025		2024

LNG volumes exported
Cargos		234		1
TBtu		876.1		3.9

LNG volumes sold (TBtu)		876.1		3.9
Weighted average price of LNG volumes sold (per MMBtu)
Fixed liquefaction fee		$	6.62	$	7.29
Commodity fee		3.93		3.95
Weighted average price of LNG volumes sold		$	10.55	$	11.24

CP2 Project. In June 2025, we commenced site work on our third LNG export facility, following receipt of final approval and notices to proceed with on-site construction from the FERC. In July 2025, Phase 1 of the CP2 Project achieved FID and obtained $15.1 billion in project financing to fund the development and construction of Phase 1 of the CP2 Project. During the year ended December 31, 2025, we incurred $6.5 billion of project costs primarily associated with construction activities and purchases of equipment procurement, of which $6.3 billion was capitalized and $203 million was expensed.

In February 2026, the CP2 Project executed a 20-year post-COD SPA for the delivery of 1.5 mtpa from Phase 2 of the CP2 Project, increasing the total expected capacity post-COD under contract from 26.0 mtpa to 27.5 mtpa.

Our Strategic Developments. In 2025, we formally initiated the development process for the Plaquemines Expansion Project with expected annual peak production capacity of 31.0 mtpa. See I tem 1A.—Business for further discussion.

We took delivery of four LNG tankers during the year ended December 31, 2025, and one LNG tanker in the first quarter of 2026. This brought our total owned fleet of LNG tankers to seven with an additional two LNG tankers that are currently under construction and will be delivered in 2026. In 2025, we used our LNG tankers to transport 61 cargos from our LNG facilities.

VGLNG Sources of Capital. In January 2025, we completed our IPO, issuing 70 million shares of our Class A common stock at a public offering price of $25.00 per share for total net proceeds of $1.7 billion. In connection with the IPO, we effectuated a 4,520.3317-for-one forward stock split of our Class A common stock.

In September 2025, Blackfin entered into the Blackfin Credit Facilities totaling $1.6 billion. Proceeds from the Blackfin Credit Facilities were used to reimburse $889 million to VGLNG for prior expenditures related to the development and construction of the Blackfin Pipeline.

In November 2025, VGLNG entered into the VGLNG Revolving Credit Facility totaling $2.0 billion. Proceeds from the VGLNG Revolving Credit Facility will be used for general corporate purposes of VGLNG and its subsidiaries.

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Key Factors Affecting Results of Operations

The key factors affecting our results of operations and financial performance are as follows:

LNG Sales. We sell LNG throughout the full lifecycle of our LNG facilities—during testing and commissioning, operations under contracted sales agreements, and through the sale of excess production capacity. We employ a portfolio contracting approach designed to sell sufficient term liquefaction capacity to support financing while optimizing revenue and cash flow.

LNG pricing structure. The LNG sales price structure under our Contracted SPAs generally includes (i) a fixed liquefaction fee, a portion of which is subject to an annual adjustment for inflation; (ii) a variable commodity fee equal to at least 115% of Henry Hub per MMBtu of LNG; and (iii) a transportation charge, if sold on a DPU basis. The LNG sales price structure of both our commissioning sales and excess capacity sales generally aligns with our Contracted SPAs for FOB delivery, whereas our DES agreements are structured with a single sales price that includes a transportation charge and is indexed to foreign gas markets, such as TTF or JKM.

Sales of LNG during commissioning. We generally sell LNG produced during the commissioning phase of our projects, prior to COD, on a forward spot or short-term contracted basis. Our ability to generate cash proceeds from the sale of commissioning LNG, and the amount of any such cash proceeds, depends primarily on the duration of the commissioning phase for each of our projects, the volume of LNG that we are able to produce during the commissioning phase, as well as the market price for LNG at the time such sales are executed. As a result, the amount of cash proceeds we are able to generate from the sale of commissioning LNG will likely differ from period to period and from project to project, and such differences could be material.

Sales of Contracted LNG. We sell LNG under post COD-SPAs and Firm-start SPAs leveraging a combination of long-term 20-year Contracted SPAs as well as short- and medium-term Contracted SPAs to optimize the average fixed liquefaction fee across our SPAs. Our ability to generate revenue, and the amount of any associated cash proceeds that we are able to generate, will be contingent upon achieving COD at each of our projects, and will vary depending on the fixed liquefaction fee under our Contracted SPAs, the variable commodity fee indexed to the Henry Hub price of gas, as well as the volume and sales prices of LNG produced in excess of committed sales under Contracted SPAs.

Sales of uncommitted excess LNG. We sell LNG produced above our Contracted SPA commitments under short‑, medium‑, or long‑term arrangements, providing commercial and pricing flexibility. Our ability to generate cash proceeds from such sales, and the amount of any such revenue that we are able to generate, will depend primarily on the volume of LNG that has been contracted under post-COD SPAs and the amount of LNG that we are able to produce at any project in excess of the nameplate capacity and the market price for LNG at the time such sales are executed. As a result, the amount of revenue and cash proceeds we are able to generate from the sale of uncommitted excess LNG, if any, will likely differ from period to period and from project to project, and such differences could be material.

Cost of feed gas. The direct costs of purchasing, transporting and converting natural gas to LNG are the primary component of our cost of sales. Under our Contracted SPAs and substantially all of our commissioning LNG sales executed to date, our customers pay a fixed liquefaction fee (which includes a CPI-linked component) per MMBtu, plus a variable commodity fee per MMBtu, in an amount equal to, depending on the applicable SPA, 115% or more of the Henry Hub gas price, which is intended to cover the price of the feed gas and gas transportation costs, and is also intended to cover certain of our operating expenses and partially adjust for inflation.

Project costs and development expenses. We currently have greenfield and expansion projects in various stages of construction and development. We expect our development, construction and commissioning costs for any particular project to increase significantly as we approach and commence the construction phase, and we expect these expenses will continue to be significant until the commissioning phase has been completed and the relevant project reaches its COD. Moreover, our project costs may be higher than we currently estimate due to many factors

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outside of our control, which could lead to higher development, construction and commissioning costs for our projects.

Operating costs. We expect to increase our project‑dedicated staff as we commence operations at our facilities. As a result, we anticipate that operating and maintenance expenses will increase significantly as we continue commissioning and operation of our projects. We outsource certain major equipment maintenance activities under long-terms service arrangements, but our various operating subsidiaries are responsible for performing day-to-day operations and maintenance work for our projects. Once projects commence full commercial operations, we anticipate that the timing of the operating and maintenance costs under the long-term service arrangements for that project will be relatively predictable, subject to inflation. Increases in operating and maintenance expenses would impact our operating margins. Further, we anticipate that insurance premiums for LNG projects may increase due to losses and claims that have arisen or been experienced in respect of other unrelated projects in other regions, or losses and claims that are large enough to impact the broader insurance market even if an LNG project is not involved.

Effective tax rates and regulations. We utilize various tax incentive programs offered by the State of Louisiana, including the industrial tax exemption, to offset local and state taxes that would otherwise be payable. However, the industrial tax exemption will expire after two 5‑year periods, which would begin on the last day of the tax year in which the Calcasieu Project, the Plaquemines Project and the CP2 Project assets, as applicable, are placed in service from an accounting perspective, and afterwards ad valorem taxes may be levied against our properties. We anticipate similar tax exemptions will be available for our greenfield and expansion projects, although any such exemptions may only be available at lower rates. The future rates at which any taxes (including ad valorem taxes, inventory taxes, franchise taxes and utility taxes) will be levied against us will impact our operating margins.

Inflation. Inflation remains a variable factor in the United States economy, and it may impact our operating margins and results of operations in the future. In particular, we anticipate that our Contracted SPAs and sales by VG Commodities that include a fixed liquefaction fee will only be partially adjusted for inflation over the contract term, as is the case with certain of our existing Contracted SPAs. In addition, we anticipate that our operating costs will experience inflationary pressure over time. We also expect to experience inflation with respect to the cost of equipment and personnel necessary to develop, construct and operate our projects. See Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors and Item 1A.—Risk Factors—Risks Relating to Our Business—We and our contractors, including our EPC contractors, may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us of this Form 10-K.

Seasonality. Seasonal weather can affect demand for LNG and accordingly can impact our ability to sell LNG during the commissioning of our facilities or after our facilities achieve their respective CODs. We have already begun experiencing, and we expect to continue to experience, the effects of market volatility and fluctuation in seasonal demand for LNG in our existing markets. For example, temperature and weather in the markets we supply, as well as the amount of natural gas in storage in such markets, may affect both power demand and power generation mix, including the portion of electricity provided through other sources of energy, such as hydroelectric, solar or wind, thus affecting the need for LNG. Further, slower-than-expected inventory withdrawal due to mild weather can decrease the demand for LNG. Conversely, extreme or extended cold conditions in the U.S. may temporarily reduce LNG export volumes as domestic demand increases, reflecting how extreme weather events may influence near-term U.S. natural gas supply-demand balances and our export scheduling flexibility. Other factors, including but not limited to the price spread between European and Asian LNG indices and the availability of LNG tankers and the routes they choose to take due to seasonal and other factors can also affect the price of LNG. As a result, our ability to generate cash proceeds from LNG sales on a spot basis or short-term basis, and to enter into new SPAs for the sale of LNG, may be impacted by such factors, which may in turn result in fluctuations in revenue during quarters of high and low demand, respectively, and could have a disproportionate effect on our results of operations. As such, our results of operations across different fiscal quarters may not be comparable or accurate indicators of our future performance. For more information on these risks, see Item 1A.—Risk Factors—Risks Relating to Our Business—Seasonal fluctuations will cause our business and results of operations to vary among quarters, which could adversely affect our business and results of operations of this Form 10-K.

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Macroeconomic Trends. Macroeconomic conditions, such as high inflation, interest rates, tariffs and global trade policy continue to be sources of volatility and uncertainty for global economic activity, and may affect our project costs and operations, as discussed above. See Item 1A.—Risk Factors—Risks Relating to Our Business—Our ability to maintain profitability and positive operating cash flows is subject to significant uncertainty of this Form 10-K. Ongoing geopolitical conflicts in Ukraine, the Middle East, Venezuela and tensions in United States-China relations may drive further economic instability and inflationary pressures, as well as increase risks for the global flow of goods, including energy. In the case of the LNG market, these geopolitical conflicts have and may continue to impact the availability of materials required for the development of LNG projects, in addition to disrupting the supply of LNG, resulting in price volatility on non-SPA volumes. For additional information on historical net spread volatility see Item 1A.—Risk Factors—Risks Relating to Our Business—Our ability to generate proceeds from sales of commissioning cargos is subject to significant uncertainty and volatility in such proceeds, given significant volatility in spot-market prices of this Form 10-K.

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Results of Operations

Year ended December 31, 2025 compared to year ended December 31, 2024

The following table shows a summary of our results of operations for the periods indicated:


	Years ended December 31,				Change
	2025		2024		($)		(%)

REVENUE	$	13,769	$	4,972	$	8,797	177	%

OPERATING EXPENSE
Cost of sales (exclusive of depreciation and amortization shown separately below)	5,920		1,351		4,569		NM
Operating and maintenance expense	975		589		386		66	%
General and administrative expense	433		312		121		39	%
Development expense	344		635		(291)		(46)	%
Depreciation and amortization	941		322		619		192	%

Total operating expense	8,613		3,209		5,404		168	%

INCOME FROM OPERATIONS	5,156		1,763		3,393		192	%

OTHER INCOME (EXPENSE)
Interest income	151		244		(93)		(38)	%
Interest expense, net	(1,454)		(584)		(870)		149	%
Gain (loss) on interest rate swaps	(220)		774		(994)		128	%
Loss on financing transactions	(267)		(14)		(253)		NM
Loss on foreign currency transactions	(3)		—		(3)		NM
Total other income (expense)	(1,793)		420		(2,213)		NM

INCOME BEFORE INCOME TAX EXPENSE	3,363		2,183		1,180		54	%
Income tax expense	630		437		193		44	%
NET INCOME	2,733		1,746		987		57	%

Less: Net income attributable to redeemable stock of subsidiary	167		144		23		16	%
Less: Net income attributable to non-controlling interests	36		59		(23)		(39)	%
Less: Dividends on VGLNG Series A Preferred Shares	270		68		202		297	%
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	2,260	$	1,475	$	785	53	%

____________

NM Percentage not meaningful.

Revenue

Revenue was $13.8 billion for the year ended December 31, 2025, an $8.8 billion, or 177%, increase from $5.0 billion for the year ended December 31, 2024. This increase was primarily due to $10.1 billion from higher LNG sales volumes primarily at the Plaquemines Project due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025. This increase was partially offset by lower LNG sales prices of $1.3 billion primarily at the Calcasieu Project after COD in April 2025, partially offset by higher LNG sales prices prior to COD in April 2025.

Gross proceeds, before deducting the cost of feed gas, attributable to Test LNG sales generated prior to the Plaquemines Project facilities being in service from an accounting perspective, and therefore recognized as an adjustment to construction in progress and not as revenue, were $132 million for the year ended December 31, 2025.

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Operating Expense

Cost of Sales

Cost of sales was $5.9 billion for the year ended December 31, 2025, a $4.6 billion increase from $1.4 billion for the year ended December 31, 2024. This increase was due to

•$3.8 billion from higher LNG sales volumes primarily at the Plaquemines Project due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025;

•$609 million due to higher costs of feed gas primarily at the Calcasieu Project; and

•$123 million unfavorable change in the fair value of our natural gas supply contracts.

Costs attributable to the production of Test LNG sales, primarily consisting of the cost of feed gas, incurred prior to the Plaquemines Project facilities being in service from an accounting perspective, and therefore recognized as an adjustment to construction in progress and not as cost of sales, was $63 million for the year ended December 31, 2025.

Operating and Maintenance Expense

Operating and maintenance expense was $975 million for the year ended December 31, 2025, a $386 million, or 66%, increase from $589 million for the year ended December 31, 2024. This increase was primarily due to $265 million in higher operating costs in support of the ramp up of LNG production at the Plaquemines Project due to an increase in non-capitalizable personnel costs, commissioning work, and operational insurance costs, as well as $175 million in higher operating costs for our LNG tankers. These increases were partially offset by a $77 million reduction in operating costs at the Calcasieu Project primarily due to lower commissioning and remediation work.

General and Administrative Expense

General and administrative expense was $433 million for the year ended December 31, 2025, an $121 million, or 39%, increase from $312 million for the year ended December 31, 2024. This increase was primarily due to increased personnel costs of $82 million due to higher employee headcount, as well as increased non-personnel costs of $38 million primarily due to increases in legal and other professional service fees, IT and insurance costs.

Development Expense

Development expense was $344 million for the year ended December 31, 2025, a $291 million, or 46%, decrease from $635 million for the year ended December 31, 2024. This decrease was primarily due to lower development costs that were expensed of $282 million as a result of the CP2 Project being declared probable during 2025, and the majority of the costs to develop the facility subsequently being capitalized.

Depreciation and Amortization

Depreciation and amortization was $941 million for the year ended December 31, 2025, a $619 million, or 192%, increase from $322 million for the year ended December 31, 2024. This increase was primarily due to placing a portion of the Plaquemines Project assets in service from an accounting perspective starting in December 2024 and throughout 2025 and placing additional LNG tankers in service throughout 2025. This increase was partially offset by a decrease of $46 million at the Calcasieu Project primarily due to an extension of the estimated useful lives of certain LNG facility assets in 2025 to align with the extended remaining terms of certain land leases to which the LNG facility assets are affixed.

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Income from Operations

Income from operations was $5.2 billion for the year ended December 31, 2025, a $3.4 billion, or 192%, increase from $1.8 billion for the year ended December 31, 2024. This increase was the result of higher revenue due to increased sales volumes, primarily at the Plaquemines Project, partially offset by lower weighted average LNG sales prices, at the Calcasieu Project subsequent to COD in April 2025, and lower development expense. These were partially offset by, higher cost of sales due to increased volumes and the cost of feed gas, higher depreciation expense, and higher operating and maintenance expense, as discussed above.

Other Income or Expense

Interest Income

Interest income was $151 million for the year ended December 31, 2025, a $93 million, or 38%, decrease from $244 million for the year ended December 31, 2024. This decrease was primarily due to lower average cash balances and interest rates during the year ended December 31, 2025, compared to the year ended December 31, 2024.

Interest Expense, Net

Interest expense, net was $1.5 billion for the year ended December 31, 2025, a $870 million, or 149%, increase from $584 million for the year ended December 31, 2024. This increase was primarily due to higher non-capitalizable interest costs due to placing a portion of the Plaquemines Project assets in service in accordance with the applicable accounting guidance and an increase in our average outstanding debt.

Gain (Loss) on Interest Rate Swaps

Loss on interest rate swaps was $220 million for the year ended December 31, 2025, a $994 million, or 128%, unfavorable change from a gain on interest rate swaps of $774 million for the year ended December 31, 2024. This unfavorable change was primarily due to a decrease in the forward interest rate curves during the year ended December 31, 2025, compared to an increase during the year ended December 31, 2024, resulting in the following:

•a $908 million unfavorable change on the Plaquemines Project interest rate swaps, which were partially settled during the year ended December 31, 2025;

•a $66 million unfavorable change on the CP2 Project interest rate swaps, which were entered into in 2025; and

•a $33 million unfavorable change on the Calcasieu Project interest rate swaps.

These were partially offset by a $13 million favorable change on the Blackfin Credit Facility interest rate swaps, which were entered into in the fourth quarter of 2025.

Loss on Financing Transactions

Loss on financing transactions was $267 million for the year ended December 31, 2025, a $253 million increase from $14 million for the year ended December 31, 2024. This increase was due to the write-off of debt issuance costs associated with the partial prepayment of the Plaquemines Construction Term Loan and the prepayment of CP2 Bridge Facilities during the year ended December 31, 2025, as compared to the write-off of debt issuance costs associated with the full prepayment of the Plaquemines Equity Bridge Facility during the year ended December 31, 2024.

Loss on Foreign Currency Transactions

Loss on foreign currency transactions was $3 million for the year ended December 31, 2025.

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Income before Income Tax Expense

Income before income tax expense was $3.4 billion for the year ended December 31, 2025, a $1.2 billion, or 54%, increase from $2.2 billion for the year ended December 31, 2024. This increase was primarily a result of an increase in income from operations, partially offset by an unfavorable change in the gain (loss) on interest rate swaps, higher interest expense and and higher loss on financing transactions, as discussed above.

Income Tax Expense

Income tax expense was $630 million for the year ended December 31, 2025, a $193 million, or 44%, increase from $437 million for the year ended December 31, 2024, primarily driven by an increase in income before income tax expense, discussed above, partially offset by a change in our effective tax rate. Our effective tax rate was 18.7% for the year ended December 31, 2025, compared to 20.0% for the year ended December 31, 2024. The 2025 effective tax rate was impacted primarily by the recognition of stock option windfall tax benefits, research and development tax credits, as well as a combination of non-deductible expenses and changes in the valuation allowance against certain deferred tax assets.

Net Income

Net income was $2.7 billion for the year ended December 31, 2025, a $1.0 billion, or 57%, increase from $1.7 billion for the year ended December 31, 2024. This increase was primarily the result of an increase in income before income tax expense, partially offset by higher income tax expense, as discussed above.

Net Income Attributable to Redeemable Stock of Subsidiary

Net income attributable to redeemable stock of subsidiary was $167 million for the year ended December 31, 2025, a $23 million, or 16%, increase from $144 million for the year ended December 31, 2024. This increase was due to higher paid-in-kind distributions on the CP Funding Redeemable Preferred Units.

Net Income Attributable to Non-controlling Interests

Net income attributable to non-controlling interests was $36 million for the year ended December 31, 2025, a $23 million, or 39%, decrease from $59 million for the year ended December 31, 2024. This decrease was primarily due to the allocation of earnings to the Calcasieu Holdings Class B common unit holders based on ownership interests subsequent to COD of the Calcasieu Project.

Dividends on VGLNG Series A Preferred Shares

Dividends on VGLNG Series A Preferred Shares were $270 million for the year ended December 31, 2025, a $202 million, or 297%, increase from $68 million for the year ended December 31, 2024. This increase was due to the issuance of the VGLNG Series A Preferred Shares in late September 2024 and the corresponding difference in the accumulation of dividends.

Net Income Attributable to Common Stockholders

Net income attributable to common stockholders was $2.3 billion for the year ended December 31, 2025, a $0.8 billion, or 53%, increase from $1.5 billion for the year ended December 31, 2024. This increase was primarily the result of the changes discussed above.

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Segment Results of Operations

We have four reportable segments, which consist of the Calcasieu Project, the Plaquemines Project, the CP2 Project, and our sales and shipping business. Each LNG project includes activity of both the respective liquefaction facility and export terminal and the associated pipeline(s) that will supply the natural gas to that facility. Our sales and shipping business is engaged in the sale and delivery of LNG to our customers and includes the operating costs associated with our fleet of LNG tankers. Activities reported in corporate, other and eliminations include immaterial operating segments, overhead costs not directly associated with our reportable segments (for example, general and administrative and marketing expenses), and inter-segment eliminations. Prior period presentations have been reclassified to conform to the current segment reporting structure to separately disclose our sales and shipping business that is now quantitatively material.

Year ended December 31, 2025 compared to year ended December 31, 2024

The following table shows a summary of our segment income (loss) from operations for the periods indicated:


	Years ended December 31,				Change
	2025		2024		($)		(%)

Calcasieu Project	$	1,316	$	2,813	$	(1,497)	(53)	%
Plaquemines Project	4,228		(217)		4,445		NM
CP2 Project	(278)		(500)		222		(44)	%
Sales and shipping	248		(20)		268		NM
Corporate, other and eliminations	(358)		(313)		(45)		14	%
Total	$	5,156	$	1,763	$	3,393	192	%

____________

NM Percentage not meaningful.

Calcasieu Project

For the year ended December 31, 2025, the Calcasieu Project had income from operations of $1.3 billion, a $1.5 billion, or 53%, decrease from $2.8 billion for the year ended December 31, 2024.

This decrease was primarily due to:

•an increase in cost of sales of $835 million due to higher costs of feed gas of $685 million, an increase in LNG sales volumes of $101 million, and an unfavorable change in fair value of natural gas supply contracts of $49 million; and

•a decrease in revenue of $791 million due to:

◦a net decrease of $1.2 billion due to lower LNG sales prices after COD in April 2025 offset by higher LNG sales prices prior to COD in April 2025, partially offset by

◦an increase in LNG sales volumes of $375 million.

These decreases were partially offset by:

•a decrease in operating and maintenance expense of $77 million due to lower commissioning and remediation work; and

•a decrease in depreciation and amortization expense of $46 million due to an extension of the estimated useful lives of certain LNG facility assets in 2025 to align with the extended remaining terms of certain land leases to which the LNG facility assets are affixed.

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Plaquemines Project

For the year ended December 31, 2025, the Plaquemines Project had income from operations of $4.2 billion, a $4.4 billion increase from a loss from operations of $217 million for the year ended December 31, 2024.

This increase was primarily due to:

•an increase in revenue of $9.2 billion from higher LNG sales volumes due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025.

This increase was partially offset by:

•an increase in cost of sales of $3.8 billion from higher LNG sales volumes due to the commencement of LNG production in December 2024 and continued ramp up of LNG production throughout 2025;

•an increase in depreciation and amortization expense of $597 million due to placing a portion of the Plaquemines Project assets in service from an accounting perspective starting in December 2024 and throughout 2025; and

•an increase in operating and maintenance expense of $265 million primarily due to higher operating costs in support of LNG production including higher non-capitalizable personnel costs, commissioning work, and operational insurance costs.

CP2 Project

For the year ended December 31, 2025, the CP2 Project had a loss from operations of $278 million, a $222 million, or 44%, decrease from $500 million for the year ended December 31, 2024. This decrease was primarily driven by lower engineering and development costs that were expensed of $282 million as a result of the CP2 Project being declared probable during 2025, and the majority of the costs to develop the facility subsequently being capitalized.

Sales and shipping

For the year ended December 31, 2025, our sales and shipping business had income from operations of $248 million, a $268 million increase from a loss from operations of $20 million for the year ended December 31, 2024.

This increase was primarily due to:

•an increase in revenue of $2.2 billion generated from the sale of LNG produced by our LNG facilities and sold through our sales and shipping business, primarily due to an increase in LNG sales volumes.

This increase was partially offset by:

•an increase in cost of sales of $1.7 billion due to the cost of LNG purchased from our LNG facilities and sold by our sales and shipping business, primarily due to an increase in LNG sales volumes;

•an increase in operating and maintenance expense of $175 million due to increased operating costs for our LNG tankers; and

•an increase in depreciation and amortization expense of $30 million due to placing additional LNG tankers in service in 2025.

Corporate, other and eliminations

For the year ended December 31, 2025, corporate, other and eliminations had a loss from operations of $358 million, a $45 million, or 14%, increase from $313 million for the year ended December 31, 2024.

This increase was primarily due to:

•an increase in general and administrative expense of $100 million primarily due to higher employee headcount and increases in legal and other professional service fees, IT and insurance costs; and

•an increase in depreciation and amortization expense of $39 million primarily due to placing additional assets in service throughout 2025.

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These increases were partially offset by:

•the impact of inter-segment eliminations of $86 million for intercompany purchases and sales of LNG between our sales and shipping business and our LNG facilities.

Liquidity and Capital Resources

General

We have been generating proceeds from the sale of LNG since the first quarter of 2022. We may incur significant costs as we continue to develop our existing and other potential natural gas liquefaction and export projects, pipeline infrastructure projects, and other complementary gas transportation projects and activities.

Funding Requirements

The operation, commissioning, construction and development of our projects requires significant capital expenditures. We expect that operating costs at our projects will be funded with cash proceeds generated by the sale of LNG.

Plaquemines Project. Approximately $0.6 billion to $1.0 billion of the current estimated Total Project Cost for the Plaquemines Project, has yet to be paid as of December 31, 2025. We believe the Plaquemines Project will have sufficient access to cash, including proceeds from commissioning sales, to fund its operations and complete the project.

CP2 Project. We currently estimate that the Total Project Cost for Phases 1 and 2 of the CP2 Project will be approximately $32.5 billion to $33.5 billion. Approximately $9.9 billion of the Total Project Cost for Phases 1 and 2 of the CP2 Project has been paid as of December 31, 2025. We believe the CP2 Project will have sufficient access to cash from the CP2 Construction Term Loan and future proceeds from commissioning LNG sales to fund the construction and completion of Phase 1 of the project. We intend to finance the construction and development of Phase 2, including the related owners’ costs, through one or more sources of debt and equity financing.

Our estimated Total Project Cost is based upon our experience to date and reflects the current inflationary environment and the potential impact of tariffs in place as of December 31, 2025. This estimate is based upon the contracts that we have in place for the CP2 Project and our construction cost experiences with the Calcasieu Project and the Plaquemines Project, as well as expected costs to construct longer pipelines for the CP2 Project than for the Calcasieu Project and the Plaquemines Project. The cost estimate for the CP2 Project reflects the current inflationary environment, and may be higher, potentially materially, compared to our current estimates as a result of many factors. Furthermore, our cost estimates might change due to factors such as unexpected delays in the construction or commissioning of our projects, the execution of any repair or warranty work and change orders or amendments to certain material construction contracts, including final terms of or amendments to any EPC contract for such projects, and/or other construction or supply contracts. For more details on these risks, see Item 1A.—Risk Factors—Risks Relating to Our Projects and Other Assets—Our estimated costs for our projects have been, and continue to be, subject to change due to various factors of this Form 10-K.

These estimates do not reflect the potential impact of any changes to tariffs that have been announced or implemented since December 31, 2025 or that may be implemented in the future. They do not reflect the potential impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on our Total Project Cost estimates. Our project budget estimates included in this Form 10-K reflect all tariffs in place, and Section 232 exemptions secured, as of December 31, 2025. Certain of our products, including our Baker Hughes sourced liquefaction train system modules and power island components, are foreign sourced and specified under our regulatory approvals, offering no domestically sourced alternative and potentially exposing us to the effects of any future tariffs that may be imposed. There can be no assurance as to the extent of any future tariffs, or

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the impact thereof on any of our estimates of Total Project Costs for our projects, which could have a material adverse effect on our construction budgets and limit our growth prospects.

Greenfield and expansion projects. We intend to finance the construction and development of our future greenfield and expansion projects, including the related owners’ costs, through one or more sources of debt and equity financing. The amount of project-level equity funding that is required for any of our projects relative to the amount of project-level debt financing may differ between our projects. Generally, we expect to finance approximately 50% to 75% of the anticipated construction costs of each of our projects with project-level debt financing (which may include non-recourse or limited recourse debt), and the remaining 25% to 50% with project-level equity—which may consist of equity contributions by us, equity financing transactions, mezzanine financing and/or other similar financing alternatives. The final terms and availability of such debt and equity financings will depend on various factors, including market conditions at the time. We may consider alternative structures to raise capital for those projects and, as a result, there can be no assurance that the financing structure for our future greenfield and expansion projects will be similar to those used for our prior or current projects.

Contractual Obligations

We have contractual obligations involving commitments to third parties that impact our liquidity and capital resource needs. In addition to the construction and development obligations discussed above, the following table summarizes our contractual obligations as of December 31, 2025:


	Years ended December 31,
	2026		2027-2030		Thereafter		Total

Operating contracts
Natural gas supply and transportation	$	3,801	$	10,319	$	12,618	$	26,738
Leases	136		347		2,662		3,145
Regasification capacity	30		172		688		890
Other	69		106		43		218
Other capital projects
LNG tankers	429		—		—		429
Pipeline development projects	884		322		—		1,206
Total	$	5,349	$	11,266	$	16,011	$	32,626

The Company has also entered into certain credit arrangements to secure the transportation of natural gas. As of December 31, 2025, the maximum undiscounted potential exposure associated with these arrangements was $260 million. This amount is not currently recognized as a liability on our consolidated balance sheet. To date, no amounts have been drawn against these arrangements.

In addition, we have significant debt and associated interest expense obligations at our subsidiaries. This consists of debt incurred by VGLNG as well as debt incurred by subsidiaries of VGLNG in connection with financing of various projects. We anticipate obtaining significant additional financing, and incurring related fees and interest, for the development of Phase 2 of the CP2 Project, our greenfield and expansion projects, our pipeline development projects, and our LNG tankers.

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Outstanding debt and associated interest obligations of the project-level subsidiaries of VGLNG have no recourse to nor are guaranteed by Venture Global or VGLNG. The following table summarizes our debt and associated interest obligations of project-level subsidiaries of VGLNG as of December 31, 2025:


	Years ended December 31,
	2026		2027-2030		Thereafter		Total

Principal maturities(1)(2)	$	817	$	9,833	$	13,078	$	23,728
Interest payments(3)	1,574		5,190		2,669		9,433
Total	$	2,391	$	15,023	$	15,747	$	33,161

_____________

(1)Reflects aggregate contractual maturities for outstanding principal as of December 31, 2025. See —Funding Requirements and Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K, for more information.

(2)Excludes $1.7 billion of redeemable preferred shares of Calcasieu Pass Funding, presented as redeemable stock of subsidiary which is redeemable at the option of the holder thereof upon the occurrence of certain events. See Item 8.—Financial Statements and Supplementary Data—Note 17 – Redeemable Stock of Subsidiary of this Form 10-K.

(3)Inclusive of the expected settlements of interest rate swaps that economically hedge our variable rate interest. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K, for more information.

Outstanding debt and associated interest obligations of VGLNG are secured by its equity interests in the direct wholly-owned subsidiaries of VGLNG that directly or indirectly own our LNG projects. The following table summarizes our debt and associated interest obligations of VGLNG as of December 31, 2025:


	Years ended December 31,
	2026		2027-2030		Thereafter		Total

Principal maturities(1)(2)	$	—	$	6,834	$	4,250	$	11,084
Interest payments(3)	973		2,945		390		4,308
Total	$	973	$	9,779	$	4,640	$	15,392

_____________

(2)Excludes $3.0 billion VGLNG Series A preferred shares presented as non-controlling interest and $270 million of corresponding annual preferred dividends that are subject to adjustment and accrue indefinitely, unless optionally redeemed in accordance with their terms. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K, for more information.

(3)The interest rate for all VGLNG Senior Secured Notes is fixed. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K for more information.

There are no material differences between the financial information presented on this Form 10-K and VGLNG's financial information other than (i) certain presentational differences related to the accounting for the VGLNG Series A Preferred Shares, and (ii) stockholders’ equity of Venture Global, including the Class A common stock and any dividends payable thereon. See Item 15.—Exhibits and Financial Statement Schedules—Schedule I Financial Information of Registrant of this Form 10-K.

For further discussion of our contractual obligations as of December 31, 2025, see Item 8.—Financial Statements and Supplementary Data—Note 15 – Commitments and Contingencies of this Form 10-K for further information.

Sources and Uses of Cash

Since our inception, we have funded our operations and capital expenditures with various forms of financing, including the issuance of equity securities, project equity financings, and borrowings at VGLNG and our project entities, as well as with cash from our operations.

We expect to meet our short-term cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash, and available borrowing capacity under our existing credit

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facilities. Additionally, we expect to meet our long-term cash requirements using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries.

The following table provides a summary of our cash and available borrowing capacity under existing credit facilities as of December 31, 2025:


	December 31, 2025

Cash and cash equivalents	$	2,355
Restricted cash	1,070
Available borrowing capacity under our credit facilities(1):
CP2 Construction Term Loan	9,390
CP2 Working Capital Facility	740
Plaquemines Working Capital Facility	637
Calcasieu Pass Working Capital Facility	279
Blackfin TLA Facility	371
Blackfin Working Capital Facility	75
VGLNG Revolving Credit Facility	2,000
Total available borrowing capacity under our credit facilities	13,492
Total cash and available borrowing capacity	$	16,917

__________

(1)Available borrowing capacity represents total borrowing capacity less outstanding borrowings and letters of credit under each of our credit facilities as of December 31, 2025.

As of December 31, 2025, our subsidiaries had approximately $34.8 billion in outstanding debt, which consisted of $11.1 billion of debt, primarily the VGLNG Senior Secured Notes, and approximately $23.7 billion of project-level debt financing.

In addition, our project‑level subsidiary, Calcasieu Funding, issued the CP Funding Redeemable Preferred Units, which may require us to make preferential cash distributions to the holders under certain circumstances. Through August 19, 2027, no distributions of available cash are permitted from Calcasieu Funding to Venture Global or its affiliates until all accrued distributions on the CP Funding Redeemable Preferred Units have been fully settled in cash. As of December 31, 2025, the accrued distribution balance on the CP Funding Redeemable Preferred Units was $796 million. Further, on and after August 19, 2027, no distributions of available cash—beyond what is deemed necessary by management to fund VGCP's operating costs, including debt service requirements—will be permitted from Calcasieu Funding to Venture Global or its affiliates until the CP Funding Redeemable Preferred Units have been fully redeemed in cash. As of December 31, 2025, the CP Funding Redeemable Preferred Units had total redemption value and aggregate liquidation preference of $1.7 billion. For the risk factors related to our business, see Item 1.—Business and Item 1A.—Risk Factors of this Form 10-K.

We commence production at our LNG projects on a sequential basis, with each liquefaction train being brought online as it is commissioned. During the year ended December 31, 2025, the Plaquemines and Calcasieu projects generated $5.9 billion and $1.1 billion of cash flow from operations, respectively.

We believe that our current cash and cash equivalents, borrowing capacity under our existing credit facilities, and the expected proceeds from sales of LNG at our projects will provide us with sufficient liquidity for at least the next 12 months, and will enable us to fund our continuing operations, our upcoming LNG tanker milestone payments, our pipeline development projects and our expected pre-FID capital expenditures with respect to our greenfield and expansion projects.

We anticipate that we will need substantial additional debt and equity capital to commence full construction activities and achieve COD for our greenfield and expansion projects. We regularly evaluate market conditions, our capital needs, our liquidity profile, and various debt, equity and equity-linked financing alternatives at Venture Global, VGLNG, our project entities, and other subsidiaries, for opportunities to raise additional debt or equity capital and to support our growth and enhance our capital structure. The availability, timing and terms of any such

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additional debt and equity financing will depend on various factors, including market conditions at the time. To the extent we issue equity or equity-linked securities, there can be no assurance that any such funding will not be expensive or dilutive to stockholders.

If we are unable to obtain additional funding on a timely basis or on terms that are acceptable to us, we will have to delay, scale back or eliminate construction plans for our greenfield and expansion projects, any of which could harm our business, financial condition and results of operations. Any delays in construction could prevent us from commencing operations when we anticipate and would prevent us from realizing anticipated cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to our incurrence of construction costs and other outflows as well as the timing of our receipt of cash flows under export contracts in relation to our incurrence of project and operating expenses. Moreover, many factors (including factors beyond our control) could result in a disparity between our liquidity sources and cash needs, including factors such as construction delays and breaches of construction agreements by our contractors. After the construction period, our business may not generate sufficient cash flow from operations, currently anticipated costs may increase or future borrowings may not be available to us in amounts sufficient to enable us to pay our indebtedness or to fund our other liquidity needs, including operating expenses. See Item 1A.—Risk Factors of this Form 10-K.

Material Financings

Venture Global IPO

In January 2025, we closed our IPO in which we issued and sold 70 million shares of Class A common stock. Our shares of Class A common stock were sold at an initial public offering price of $25.00 per share, which generated net proceeds of approximately $1.7 billion after deducting underwriting discounts and commissions of $70 million and approximately $10 million of offering expenses. See additional discussion in Item 8.—Financial Statements and Supplementary Data—Note 16 – Equity of this Form 10-K for further information.

VGLNG Debt and Equity Financing

VGLNG Senior Secured Notes. In May 2023, VGLNG issued $2.25 billion aggregate principal amount of 8.125% Senior Secured Notes due 2028, or the VGLNG 2028 Notes, and $2.25 billion aggregate principal amount of 8.375% Senior Secured Notes due 2031, or the VGLNG 2031 Notes. The VGLNG 2028 Notes bear interest at a rate of 8.125% per annum and mature on June 1, 2028. The VGLNG 2031 Notes bear interest at a rate of 8.375% per annum and mature on June 1, 2031. The interest on each such series of notes is payable semi-annually in arrears on each June 1 and December 1.

In October 2023, VGLNG issued $2.5 billion aggregate principal amount of 9.500% Senior Secured Notes due 2029, or the VGLNG 2029 Notes, and $1.5 billion aggregate principal amount of 9.875% Senior Secured Notes due 2032, or the VGLNG 2032 Notes. In addition, in November 2023, VGLNG issued an additional $500 million aggregate principal amount of VGLNG 2029 Notes, and an additional $500 million aggregate principal amount of VGLNG 2032 Notes. The VGLNG 2029 Notes bear interest at a rate of 9.500% per annum and mature on February 1, 2029. The VGLNG 2032 Notes bear interest at 9.875% per annum and mature on February 1, 2032. The interest on each such series of notes is payable semi-annually in arrears on each February 1 and August 1, commencing on August 1, 2024.

In July 2024, VGLNG issued $1.5 billion aggregate principal amount of 7.000% Senior Secured Notes due 2030, or the VGLNG 2030 Notes. The VGLNG 2030 Notes bear interest at a rate of 7.000% per annum and mature on January 15, 2030. The interest on each such series of notes is payable semi-annually in arrears on each January 15 and July 15, commencing on January 15, 2025.

The VGLNG 2028 Notes, the VGLNG 2029 Notes, the VGLNG 2031 Notes, the VGLNG 2032 Notes and the VGLNG 2030 Notes are secured by first-priority liens in, subject to permitted liens and certain other exceptions, substantially all of our existing and future assets, if any, including our direct wholly-owned subsidiaries that directly

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or indirectly own the Calcasieu Project, the Plaquemines Project, the CP2 Project, the CP3 Project, or any related pipeline.

VGLNG Series A Preferred Shares. In September 2024, VGLNG issued three million shares of 9.000% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, with a $1,000 liquidation preference per share, or the VGLNG Series A Preferred Shares, for aggregate gross proceeds of $3.0 billion. The VGLNG Series A Preferred Shares are not convertible into any other securities and have limited voting rights. Cumulative cash dividends on the VGLNG Series A Preferred Shares are payable semi-annually, in arrears, on each March 30 and September 30, when, as and if declared by the board of directors of VGLNG.

VGLNG Revolving Credit Facility. On November 7, 2025, VGLNG entered into the $2.0 billion senior secured revolving credit VGLNG Revolving Credit Facility. Borrowings under the VGLNG Revolving Credit Facility bears interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for SOFR-based loan is 2.500% and the set margin rate for base rate loan is 1.500%. The Company also incurs commitment fees of 0.350% of the undrawn available commitments of the VGLNG facility. Proceeds from the VGLNG Revolving Credit Facility can be used for general corporate purposes of VGLNG and its subsidiaries. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt and Item 8.—Financial Statements and Supplementary Data—Note 18 – Non-Controlling Interests of this Form 10-K for further discussion.

Project Debt and Equity Financing

Calcasieu Project. In August 2019, our subsidiary, VGCP, obtained $5.8 billion in project financing consisting of an approximately $5.5 billion senior secured construction term loan, or the Calcasieu Pass Construction Term Loan, and a $300 million senior secured working capital facility, or the Calcasieu Pass Working Capital Facility, or collectively, the Calcasieu Pass Credit Facilities, that mature on August 19, 2026 and bear interest at SOFR plus an applicable margin, payable monthly in arrears. The proceeds from the Calcasieu Pass Credit Facilities were used to fund the costs of developing, constructing and commissioning the Calcasieu Project. In September 2021, VGCP upsized the Calcasieu Pass Working Capital Facility by an incremental $255 million to $555 million. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt and Item 8.—Financial Statements and Supplementary Data—Note 18 – Non-Controlling Interests of this Form 10-K for further discussion.

In May 2019, our subsidiaries, Calcasieu Funding and Calcasieu Holdings, entered into two unit purchase agreements with certain funds associated with Stonepeak Infrastructure Partners, pursuant to which Calcasieu Funding and Calcasieu Holdings issued 9 million and 4 million preferred units, respectively, for $1.3 billion of total gross proceeds at a face value of $100 per preferred unit. These transactions closed in August 2019 and proceeds were used to fund the equity portion of the cost of developing, constructing and commissioning the Calcasieu Project. Upon COD of the Calcasieu Project in April 2025, the CP Holdings Convertible Preferred Units converted into Class B common units, representing a 23% ownership interest in the Calcasieu Project. See Item 8.—Financial Statements and Supplementary Data—Note 17 – Redeemable Stock of Subsidiary and Item 8.—Financial Statements and Supplementary Data—Note 18 – Non-Controlling Interests of this Form 10-K for further discussion.

In August 2021, VGCP issued $2.5 billion aggregate principal amount of senior secured notes, consisting of $1.25 billion of senior secured notes due 2029, or the VGCP 2029 Notes, and $1.25 billion of senior secured notes due 2031, or the VGCP 2031 Notes. The VGCP 2029 Notes bear interest at a rate of 3.875% per annum and the VGCP 2031 Notes bear interest at a rate of 4.125% per annum, with each series of notes payable semi-annually in arrears on February 15 and August 15 of each year. The VGCP 2029 Notes will mature on August 15, 2029 and the VGCP 2031 Notes will mature on August 15, 2031. In November 2021, VGCP issued $1.25 billion aggregate principal amount of senior secured notes due 2033, or the VGCP 2033 Notes. The VGCP 2033 Notes bear interest at a rate of 3.875% per annum, payable semi-annually in arrears on May 1 and November 1 of each year. The VGCP 2033 Notes will mature on November 1, 2033. In January 2023, VGCP issued $1.0 billion aggregate principal amount of senior secured notes due 2030, or the VGCP 2030 Notes, and together with the VGCP 2029 Notes, the VGCP 2031 Notes and the VGCP 2033 Notes, the VGCP Senior Secured Notes. The VGCP 2030 Notes bear interest at a rate of 6.250% per annum, payable semi-annually in arrears on January 15 and July 15 of each year, beginning July 15, 2023. The VGCP 2030 Notes will mature on January 15, 2030. The aggregate proceeds

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from these issuances were used to prepay $4.2 billion outstanding under the Calcasieu Pass Credit Facilities. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K for further discussion.

Plaquemines Project. In May 2022, our subsidiary, VGPL, obtained approximately $9.6 billion in project financing consisting of an approximately $8.5 billion term loan facility, or the Plaquemines Construction Term Loan, and a $1.1 billion working capital revolving facility, or the Plaquemines Working Capital Facility, or collectively, the Plaquemines Credit Facilities, that matures in May 2029, to fund the development and construction of Phase 1 of the Plaquemines Project. The project financing facilities were upsized in March 2023 to fund the development and construction of Phase 2 of the Plaquemines Project. In the aggregate, the upsized Plaquemines Credit Facilities, are comprised of an approximately $12.9 billion Plaquemines Construction Term Loan and a $2.1 billion Plaquemines Working Capital Facility, that mature on May 25, 2029 and bear interest at SOFR plus an applicable margin, payable monthly in arrears. In connection with the upsize, PL Holdings entered into the Plaquemines Equity Bridge Facility, an approximately $1.7 billion secured credit facility equity bridge credit facility to fund a portion of project costs for the Plaquemines Project. In July 2024, we prepaid the remaining outstanding amount of the Plaquemines Equity Bridge Facility in full using proceeds from the VGLNG 2030 Notes. The net proceeds from the project financing arrangements will be used be used to fund the costs of financing, developing, constructing, and commissioning the Plaquemines Project. See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K for further discussion.

In April 2025, our subsidiary, VGPL issued $2.5 billion aggregate principal amount of senior secured notes, consisting of $1.25 billion of senior secured notes due 2033, or the VGPL 2033 notes, and $1.25 billion of senior secured notes due 2035, or the VGPL 2035 notes. The VGPL 2033 notes bear interest at a rate of 7.500% per annum and the VGPL 2035 notes bear interest at a rate of 7.750% per annum, with interest on each series of notes payable semi-annually in arrears on May 1 and November 1 of each year. The VGPL 2033 notes will mature on May 1, 2033 and the VGPL 2035 notes will mature on May 1, 2035. The proceeds from this issuance, along with swap breakage proceeds, were used to prepay $2.7 billion outstanding under the Plaquemines Construction Term Loan.

In July 2025, VGPL issued $4.0 billion aggregate principal amount of senior secured notes, consisting of $2.0 billion of senior secured notes due 2034, or the VGPL 2034 notes, and $2.0 billion of senior secured notes due 2036, or the VGPL 2036 notes. The VGPL 2034 notes bear interest at a rate of 6.500% per annum and the VGPL 2036 notes bear interest at a rate of 6.750% per annum, with interest on each series of notes payable semi-annually in arrears on January 15 and July 15 of each year. The VGPL 2034 notes will mature on January 15, 2034 and the VGPL 2036 notes will mature on January 15, 2036. The proceeds from this issuance, along with swap breakage proceeds, were used to prepay $4.5 billion outstanding under the Plaquemines Construction Term Loan.

In December 2025, VGPL issued $3.0 billion aggregate principal amount of senior secured notes, consisting of $1.75 billion of senior secured notes due 2030 or the VGPL 2030 notes, and a $1.25 billion of senior secured notes due 2034 or the VGPL 2034. The VGPL 2030 notes bear interest at a rate of 6.125% per annum and the VGPL 2034 notes bear interest at a rate of 6.500% per annum, with interest on each series of notes payable semi-annually in arrears on June 15 and December 15 of each year. The VGPL 2030 notes will mature on December 15, 2030 and the VGPL 2034 notes will mature on June 15, 2034. The proceeds from this issuance, along with swap breakage proceeds, were used to prepay $3.2 billion outstanding under the Plaquemines Construction Term Loan.

CP2 Project. In May 2025, our subsidiary, CP2, entered into the CP2 Bridge Facilities, a $3.0 billion secured credit facility to fund a portion of the project costs for the CP2 Project prior to the closing of the full project financing for Phase 1 of the CP2 Project. Borrowings under the CP2 Bridge Facilities bear interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for SOFR-based loans is 3.500% and the set margin rate for base rate loans is 2.500%. The Company also incurred commitment fees on the undrawn available commitments of the CP2 Bridge Facilities.

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In July 2025, Phase 1 of the CP2 Project achieved FID and we obtained $15.1 billion in project financing to fund the development and construction of Phase 1 of the CP2 Project. CP2 Holdings entered into the $3.0 billion secured CP2 Holdings EBL Facilities, due July 28, 2028. Borrowings under the CP2 Holdings EBL Facilities bear interest at a set margin rate over the debt term plus, at the Company's election, either a SOFR or base rate. The set margin rate for SOFR-based loans is 3.500% and the set margin rate for base rate loans is 2.500%. Interest on SOFR-based loans is due and payable at the end of each interest period (but at least every three months) and interest on base rate loans is due and payable at the end of each calendar quarter. CP2, as borrower, and CP2 Procurement and CP Express, as guarantors, entered into the $12.1 billion senior secured CP2 Credit Facilities, due July 28, 2032. Borrowings under the CP2 Credit Facilities bear interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for the SOFR-based loans ranges from 2.250% to 2.750% and the set margin rate for the base rate loans ranges from 1.250% to 1.750%. The Company also incurs commitment fees from 0.788% to 0.963% of the undrawn available commitments of the CP2 Working Capital Facility. Interest on SOFR-based loans is due and payable at the end of each interest period (but at least every three months) and interest on base rate loans is due and payable at the end of each calendar quarter.

A portion of the proceeds from the project financing was used to prepay the outstanding CP2 Bridge Facilities in full and pay costs incurred in connection with the project financing. The remaining proceeds from the project financing will be used to fund the costs of financing, developing, constructing, and placing in service Phase 1 of the CP2 Project.

Pipeline infrastructure projects. In September 2025, our subsidiary, Blackfin, entered into the $1.6 billion senior secured Blackfin Credit Facilities. Under the Blackfin Credit Facilities, the Blackfin TLA Facility and Blackfin Working Capital Facility are due September 29, 2030 and the Blackfin TLB Facility is due September 29, 2032 . Borrowings under the Blackfin TLA Facility and Blackfin TLB Facility bear interest at a set margin over the debt term, plus, at the Company's election, either a SOFR or base rate. The set margin rate for the Blackfin TLA Facility for SOFR-based loans is 2.250% and the set margin rate for base rate loans is 1.250%, subject to future increases. The set margin rate for the Blackfin TLB Facility for SOFR-based loans is 3.000% and the set margin rate for base rate loans is 2.000%. The Company also incurs commitment fees from 0.438% to 0.875% of the undrawn available commitments under the Blackfin TLA Facility and Blackfin Working Capital Facility. Interest on SOFR-based loans is due and payable at the end of each interest period (but at least every three months) and interest on base rate loans is due and payable at the end of each calendar quarter.

Proceeds from the Blackfin Credit Facilities were used to reimburse $889 million to VGLNG for prior expenditures related to the development and construction of the Blackfin Pipeline, and pay certain costs incurred in connection with the project financing. The remaining proceeds will be used to fund a portion of the costs to develop, construct and manage the Blackfin Pipeline.

See Item 8.—Financial Statements and Supplementary Data—Note 11 – Debt of this Form 10-K for additional discussion of material financing activity.

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Cash Flows

Year ended December 31, 2025 compared to year ended December 31, 2024

The following table shows a summary of our consolidated cash flows for the periods indicated:


	Years ended December 31,				Change
	2025		2024		($)		(%)

Net cash from operating activities	$	6,566	$	2,149	$	4,417	206	%
Net cash used by investing activities	(13,220)		(14,159)		939		(7)	%
Net cash from financing activities	5,465		10,752		(5,287)		(49)	%

Operating activities

Net cash from operating activities for the year ended December 31, 2025 was $6.6 billion, a $4.4 billion, or 206%, increase from $2.1 billion for the year ended December 31, 2024.

Change in cash from operating activities (in billions)

•The increase in cash received from LNG sales was due to $9.3 billion of higher cash receipts primarily at Plaquemines from increased LNG sales volumes, partially offset by $0.9 billion lower cash receipts at Calcasieu from lower LNG sales prices.

•The increase in cash paid for feed gas was due to $3.2 billion of higher payments at Plaquemines from increased LNG sales volumes and $696 million at Calcasieu from higher costs for feed gas; and

•The increase in cash received for the settlement of derivatives was primarily due to $1.1 billion of proceeds from the pro rata settlement of a portion of the interest rate swaps associated with the Plaquemines Credit Facilities in 2025, with no similar settlements in 2024.

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Investing activities

Net cash used by investing activities for the year ended December 31, 2025 was $13.2 billion, a $0.9 billion, or 7%, decrease from $14.2 billion for the year ended December 31, 2024. The decrease in net cash outflows was primarily due to:

Change in cash used by investing activities (in billions)

•The decrease of $352 million of cash paid for capital expenditures comprised of the following:


	Years ended December 31,				Change
	2025		2024		($)

Plaquemines Project	$	(5,503)	$	(9,414)	$	3,911
CP2 Project	(5,256)		(2,334)		(2,922)
Pipeline projects	(933)		(509)		(424)
LNG tankers	(754)		(403)		(351)
Calcasieu Project	(65)		(37)		(28)
VGLNG capitalized interest	(558)		(668)		110
Other	(296)		(352)		56
Total	$	(13,365)	$	(13,717)	$	352

•The decrease of $500 million of other investing cash outflows was comprised of the following:

◦a decrease of $298 million due to cash outflows from investments in interest bearing deposits during the year ended December 31, 2024 as compared to cash inflows from the redemption of certificates of deposit during the year ended December 31, 2025; partially offset by

◦an increase of $132 million due to cash inflows from Test LNG proceeds during the year ended December 31, 2025, with no similar inflow during the year ended December 31, 2024.

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Financing activities

Net cash from financing activities for the year ended December 31, 2025 was $5.5 billion, a $5.3 billion, or 49%, decrease from $10.8 billion for the year ended December 31, 2024. The decrease in net cash inflows was primarily due to:

Change in cash from financing activities (in billions)

•The change in the issuance and repayment of debt is primarily comprised of the following:


	Years ended December 31,				Change
	2025		2024		($)

Issuance of debt and draws on Credit Facilities
Plaquemines Project	$	10,037	$	7,776	$	2,261
CP2 Project	5,168		—		5,168
Pipeline projects	1,124		—		1,124
VGLNG	—		1,500		(1,500)
Other	—		84		(84)
Total issuance of debt	$	16,329	$	9,360	$	6,969

Repayment of debt
Plaquemines Project	$	(10,573)	$	(727)	$	(9,846)
CP2 Project	(308)		—		(308)
Calcasieu Project	(190)		(178)		(12)
Total repayment of debt	$	(11,071)	$	(905)	$	(10,166)

Total change in issuance and repayments of debt, net	$	5,258	$	8,455	$	(3,197)

•The change in the proceeds from the issuance of Class A Common Stock of $1.8 billion is due to our IPO during the during the year ended December 31, 2025, with no similar activity during the same period in 2024; and

•The change in the issuance of the VGLNG Series A Preferred Shares of $3.0 billion during the year ended December 31, 2024, with no similar activity during the same period in 2025.

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Key Trends and Uncertainties

Management expects several factors to influence our operations, financial condition and cash flows in 2026 and beyond. While proceeds generated from the sale of LNG produced by our Calcasieu and Plaquemines projects may offset certain near-term uncertainties, events that arise or evolve differently from current assumptions could materially affect our results. We continue to monitor these developments and respond as conditions warrant. For additional discussion, see Item 1.—Business and Item 1A.—Risk Factors of this Form 10-K.

Macroeconomic

Global economic volatility may heighten risks related to tariffs, labor availability, capital market access, exchange rate and interest rate fluctuations, and market balance and margins.

Tariffs and trade policy — The global trade environment remains fluid. United States and foreign tariff actions, including potential retaliatory measures, may lead to higher equipment and material costs for our construction projects and affect LNG demand or pricing in affected markets. We rely on significant equipment imported from the European Union, or EU, and any deterioration in trade relations or new duties could increase project costs and reduce competitiveness. The potential cost impact is currently expected to be concentrated in our CP2 Project. The impact of tariffs effective as of December 31, 2025 has been incorporated into our current budget for the CP2 Project. The cumulative impact of all new tariffs implemented in 2025 increased our total expected capital costs by approximately $600 million. Because the Plaquemines Project has already procured substantially all critical equipment, tariff-related effects are expected to be immaterial for that project. Future projects and expansions may also be subject to higher costs depending on the timing and scope of procurement activities; our project budgets for these initiatives also reflect our best estimates of tariffs at the currently enacted rates. This assessment does not reflect the impact of the U.S. Supreme Court ruling against the validity of the tariffs imposed by the federal government, nor the federal government’s decision to impose incremental baseline tariffs, all of which could have a material impact on applicable tariff rates and global trade. The impact of this ruling, and the federal government's response, are unknown and could alter our estimated capital project costs. Global economic uncertainty and any related reduction in economic activity or capital investment as a result of tariffs and any retaliatory actions from other countries could have a material impact on our financial condition, results of operations and/or cash flows through reduced demand and competitiveness for both our long-term and short-term contract sales in countries that may be affected by those policies. The Company continues to monitor this situation.

Labor market — Competition for skilled labor along the Gulf Coast remains intense. Persistent shortages in highly skilled construction labor—driven by concurrent LNG construction and major infrastructure and datacenter development—may amplify wage pressure, recruitment and retention difficulty. Sustained tightness in the labor pool could raise project costs or extend construction timelines. This could materially increase our estimated project costs, which include significant labor costs, and could have a material impact on our financial condition, results of operations and/or cash flows.

Capital markets and interest rates — Capital markets have experienced recent volatility and liquidity constraints due to uncertainty around the global economic impact of tariffs, inflation and monetary policy. Although the annual rate of inflation has moderated, future changes in interest rate policy could reignite inflationary pressures or increase the overall cost of capital. Such volatility may adversely impact access to the market for corporate or project lending or lead to higher borrowing costs. We aim to mitigate our exposure to interest rate volatility through interest rate swaps, but we will not be able to mitigate all interest rate risk. Additionally, we may sometimes prioritize access to capital or capital recycling over interest rates when determining when to access capital markets.

Market Balance and Margins — Following a period of strong global LNG demand from 2022 to 2025, the market is transitioning to a period of increased supply and normalized shipping conditions. Additionally, higher Henry Hub natural gas prices, elevated feed gas transportation (including costs to supply feed gas to less liquid delivery locations, or basis differentials), and marine freight costs could compress our operating margins if the spread between total delivered costs and the prices at which we sell LNG narrows. This margin pressure is currently

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most evident for sales indexed to the TTF benchmark, which has remained comparatively stable over recent periods even as feed gas (largely linked to Henry Hub) and shipping costs have increased. For example, beginning in late 2025 and into early 2026, Henry Hub prices rose sharply and basis differentials (at our Plaquemines Project) intensified, while TTF indices remained steady, narrowing price spreads on certain cargos. If these market conditions persist, our margins on spot and short-term sales could be reduced, and together with continued cost inflation or sustained high feed gas and freight prices, could adversely affect our cash flows and project returns. Our long-term contract portfolio and low-cost production model are expected to mitigate some of these impacts, but prolonged margin pressure could have a material impact on our financial condition, results of operations and/or cash flows.

Geopolitical

Evolving global political and energy-policy conditions continue to shape LNG demand and pricing. In January 2026, the EU voted a plan into law to phase out Russian-sourced gas and LNG by 2027. The ban is expected to create a lasting increase in demand for non-Russian LNG imports, including U.S. supply. While supportive of long-term growth, the transition may create short-term uncertainty in market pricing. Elsewhere, geopolitical developments in Venezuela—including fluctuations in sanctions policy and potential shifts in regional oil and gas production—may influence global supply balances, energy pricing and investment flows across the Americas. Broader uncertainty from conflicts in major energy-producing regions like the Middle East, selective sourcing decisions in Asia, and international trade realignments could also affect contract timing, volumes and average realized prices. We continue to monitor these developments and assess potential implications on our financial condition, results of operations and/or cash flows.

Regulatory

Recent U.S. policy actions have generally supported continued LNG development, including the DOE's resumption of Non-FTA Nation export authorizations and final approvals for our CP2 Project. While these trends are favorable, they remain subject to change. These actions have resulted in increased opportunities to continue development of our projects, including our expansion projects. While we cannot predict whether these trends will continue or whether our applications, approvals or permits will attract significant opposition in the permitting processes, we intend to continue to progress our projects through the various permitting and regulatory channels over their expected timelines. Any future significant changes in this trend could have a material impact on our financial condition, results of operations and/or cash flows.

Post-COD SPAs

The Calcasieu Project is involved in disputes and arbitration proceedings with its post-COD SPA customers. Such customers are asserting, among other claims, that the Calcasieu Project was delayed in achieving COD under its post-COD SPAs. Following the positive resolution of three arbitration proceedings, the Calcasieu Project remains involved in arbitration proceedings with four of its post-COD SPA customers.

We were notified in October 2025 that a partial final award had been issued in the arbitration proceedings with BP. The award issued by the arbitration tribunal found that the VGCP had breached its obligations to declare COD of the Calcasieu Project in a timely manner and act as a “Reasonable and Prudent Operator” pursuant to the BP post-COD SPA, along with certain other obligations. Remedies were not addressed in the partial final award and will be determined in a separate damages hearing which has not been scheduled but is anticipated to occur in 2026 or 2027. A final award is expected to be issued following the damages portion of the hearing. Based on the terms of the award, the Company does not anticipate that the final award will be subject to the seller aggregate liability limitation in the BP post-COD SPA. The remedies sought by BP include damages ranging from $3.7 billion to potentially in excess of $6.0 billion, as well as interest, costs and attorneys’ fees. We believe BP’s theory and calculations of damages are without merit and that the magnitude of damages sought by BP is not recoverable under the express terms of the post-COD SPA, which include express limits on the tribunal’s jurisdictional authority, although there can be no assurance as to the outcome of the damages portion of the hearing.

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The remedies sought by the other three Calcasieu Project post-COD customers in arbitration proceedings include damages ranging between $3.4 billion and $4.1 billion in the aggregate, rather than the termination of the post-COD SPA. We believe these three disputes are subject to the relevant seller aggregate liability limitation under the applicable post-COD SPA, which amount to $595 million in the aggregate. However, these customers are also disputing whether the liability limitations in such post-COD SPAs are applicable, and therefore are claiming damages in excess of the liability limitations.

If these disputes are not resolved favorably, adverse outcomes could require substantial payments that exceed our liability accruals or the relevant limits under the post-COD SPAs. Such payments could negatively affect project-level cash flows, restrict distributions to the Company or cause acceleration of related debt under project-financing agreements. The Company's best estimate of potential financial impacts of these disputes are currently reflected in our financial statements and disclosures.

For further discussion, see Item 1A.—Risk Factors—Risks Relating to Regulation and Litigation—If we are unsuccessful in any current or potential future legal proceedings with customers, the amounts that we are required to pay may be substantial or certain of our post-COD SPAs may be terminated, which may lead to an acceleration of all our debt for the relevant project and adversely impact the trading price of our Class A common stock, Note 4 – Revenue from Contracts with Customers in Item 8.—Financial Statements and Supplementary Data of this Form 10-K, and Part I Item 3.—Legal Proceedings of this Form 10-K.

Critical Accounting Policies and Estimates

Use of Estimates

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. We evaluate our assumptions on an ongoing basis. The accounting policies and estimates discussed below are considered by our management to be critical to an understanding of our financial statements as their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. While we believe the estimates used in the preparation of the consolidated financial statements are appropriate, actual results could differ from these estimates.

Revenue from Contracts with Customers

The transaction price defined in our contracts for the sale of LNG to third-party customers includes both fixed and variable components including variable consideration for contingent payments for non-performance, delays, or other damages, which may be due from the Company and could result in the significant reversal of revenue. Any estimates for contingent payments are recognized as a reduction to the transaction price until the future significant reversal of revenue is no longer probable of occurring or once the uncertainty is resolved. For further discussion, see Item 8.—Financial Statements and Supplementary Data—Note 4 – Revenue from Contracts with Customers of this Form 10-K, for more information.

Critical Accounting Policies

Revenue Recognition

The majority of our nameplate capacity produced at our projects after COD will be sold under long-term 20-year Contracted SPAs. We aim to market and sell the expected nameplate capacity at our subsequent projects under a combination of long-term 20-year SPAs as well as short- and medium-term contracts to optimize the average fixed liquefaction fee across our SPAs. Delivery under post-COD SPAs commences upon achieving COD of the respective LNG facilities, which has only occurred for our Calcasieu Project. Delivery under our Firm-start SPAs commences upon a contractually defined date. LNG produced during the commissioning phase prior to an LNG

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facility achieving COD is sold to various customers under master SPAs, either as single cargo or as multiple cargos to be loaded over a period of time, and are based on spot and/or forward prices at the time of execution.

We recognize revenue when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. Revenue from the sale of LNG is recognized at the point in time when the LNG is delivered to the customer at the agreed upon LNG terminal which is the point when legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each molecule of LNG is viewed as a separate performance obligation. Under our projects' LNG sales agreements, LNG may be transferred to the customer on delivery terms including FOB, DPU or DES. When LNG is sold on terms other than FOB, transportation costs incurred by us are considered to be fulfillment costs and are not separate performance obligations within the arrangement. The majority of the Company's post-COD SPAs are sold FOB. The stated contract price, including both fixed and variable components, is representative of the stand-alone selling price for LNG at the time the contract was negotiated. The Company's LNG sales agreements include provisions for contingent payments for non-performance, delays, or other damages, which may be due from the Company, and represent variable consideration. Any estimates for contingent payments are based on either the Company's best estimate of the most likely outcome or the expected value, depending on which method best predicts the total net consideration to which the Company will be entitled over the term of the LNG sales agreement. Payments, and estimates for contingent payments, made by the Company are recognized as a reduction to the transaction price (as an adjustment to the fixed liquefaction fee) as LNG is delivered to customers over the term of the LNG sales agreement. Payment terms are within 30 days after the LNG is delivered.

Proceeds from the sale of test LNG generated during the early commissioning of an LNG project are determined based on estimates of LNG production generated from commissioning activities and recognized as a reduction to the cost basis of construction in progress until assets are placed in service in accordance with the accounting guidance.

Capitalization of Development and Construction Costs

Generally, the costs incurred to develop our projects are treated as development expenses until management concludes that construction and completion of the relevant project is considered probable. Costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our projects. In assessing probability, we consider whether: (i) management has committed to funding construction of the project, (ii) financing for the project is available and (iii) the ability exists to meet the necessary local and other governmental regulations. Certain costs are capitalized prior to a project meeting the criteria otherwise necessary for capitalization, which requires judgment and is based upon our assessment of our ability to realize the future benefits associated with these assets. For example, we have capitalized the cost of equipment and materials that are expected to be used on projects that are not yet probable when the equipment and materials have alternative use and are otherwise recoverable in other projects or for resale. Our construction and equipment supplier arrangements also contain various terms including retainage, performance bonuses, and liquidated damages, that impact the amount and timing of the recognition of the related costs. For further discussion, see Item 8.—Financial Statements and Supplementary Data—Note 6 – Property, Plant and Equipment of this Form 10-K, for more information.

Derivative Instruments

We reflect all contracts that meet the definition of a derivative, except those designated and qualifying as NPNS as either assets or liabilities on the consolidated balance sheets at fair value. Changes in the fair value of derivative instruments are recognized in earnings, unless we elect to apply hedge accounting and meet the specified criteria in ASC 815, Derivatives and Hedging. We designate derivatives instruments as cash flow hedges based on all available facts and circumstances.

We enter into interest rate swap agreements to mitigate volatility arising from changes in interest rates. We do not utilize derivatives for trading or speculative purposes. Derivative instruments are recognized at their fair values on the consolidated balance sheets. Changes in fair value of derivative instruments designated as cash flow hedges are recognized in accumulated other comprehensive income or loss, or AOCL, until the hedged transaction affects

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earnings, at which time the deferred gains and losses are reclassified to earnings. Cash flows of our derivatives which are not designated as hedging relationships are classified as operating activities in the consolidated statements of cash flows unless the derivatives contain an other-than-insignificant financing element at inception, in which case the associated cash flows are classified as financing activities. Derivative assets and liabilities are presented net on the consolidated balance sheets when a legally enforceable master netting arrangement exists with the counterparty.

We discontinue hedge accounting on a prospective basis if the derivative is no longer expected to be highly effective as a hedge, if the hedged transaction is no longer probable of occurring, or if we de-designate the instrument as a cash flow hedge. Any gain or loss in AOCL at the time of de-designation is reclassified into earnings in the same period the hedged transaction affects earnings unless the underlying hedged transaction is probable of not occurring, in which case, any gain or loss in AOCL is reclassified into earnings immediately. For further discussion, see Item 8.—Financial Statements and Supplementary Data—Note 12 – Derivatives of this Form 10-K for more information.

Income Taxes

We account for U.S. federal, state and foreign income taxes under the asset and liability method, which requires the recognition of deferred income tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine income tax assets and liabilities based on the differences between the financial statement and income tax basis for assets and liabilities using the enacted statutory tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rate on deferred income tax assets and liabilities is recognized in income in the period that includes the enactment date.

A valuation allowance is provided for deferred income taxes if it is more-likely-than-not these items will either expire before we are able to realize their benefits or if future deductibility is uncertain. Additionally, we evaluate tax positions under a more-likely-than-not recognition threshold and measurement analysis before the positions are recognized for financial statement reporting.

Our accounting policy for releasing the income tax effects from AOCL occurs on a portfolio basis. For further discussion, see Item 8.—Financial Statements and Supplementary Data—Note 14 – Income Taxes of this Form 10-K for more information.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of December 31, 2025, our exposure to market risk for changes in interest rates related primarily to our variable rate debt and our investment portfolio. The Company's credit facilities, accrued interest at term SOFR, plus an applicable margin. Therefore, fluctuations in interest rates will impact our consolidated financial statements. A rising interest rate environment will increase the amount of interest paid on these loans. We entered into interest rate hedge arrangements to manage our interest rate exposure under the Company's credit facilities. As of December 31, 2025 and 2024, we had hedges targeting between 50% to 97% of our variable rate debt. For the years ended December 31, 2025 and 2024, a hypothetical 100 basis point increase in interest rates would have increased our interest cost by $42 million and $26 million, respectively.

The fair value of our credit facilities will generally fluctuate with movements of interest rates, increasing in periods of declining rates of interest and declining in periods of increasing rates of interest. A hypothetical 100 basis point increase or decrease in interest rates would not have had a material impact on the fair value of our credit facilities as of December 31, 2025 and 2024.

The primary objective of our investment activities is to preserve our capital for the purpose of funding our operations. We do not enter into investments for trading or speculative purposes. We generally invest our cash in investments with short maturities or with frequent interest reset terms. Accordingly, our interest income fluctuates

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with short-term market conditions. As of December 31, 2025 and 2024, our investment portfolio consisted of $340 million and $1.5 billion, respectively. Due to the short-term nature of our investment portfolio, our exposure to interest rate risk is minimal.

To the extent we utilize additional debt financing, we may incur fixed or floating rate debt or a combination thereof. We will have exposure to changes in interest rates until such time as the interest rates on any such instruments are determined. We will also have exposure to changes in interest rates with respect to any floating rate debt we incur, unless we enter into interest rate hedges with respect to any such exposure.

Commodity Price Risk

We face commodity price exposure in connection with the construction of our projects, and we expect to also face commodity price exposure during operation of our projects, which we seek to mitigate through certain pricing mechanisms in our SPAs.

In connection with the construction of our projects, our exposure to commodity price risk relates primarily to the commodity fluctuations in the time between when we execute our construction contracts and key owner furnished equipment contracts, and when individual commodity pricing is finalized once procured. Our reimbursable EPC contract target price considers anticipated inflation and models financed contingency to absorb commodity pricing pressure, labor cost increases, and cost overruns for the construction of the relevant project. We expect the potential impacts from commodity price risk will fluctuate with changes in prices of the relevant commodities to be utilized in the construction of the relevant project, which will primarily be steel, aluminum, nickel, concrete and diesel fuel. For our future projects we may be exposed to changes in prices of such commodities if the relevant project is delayed in issuing notice to proceed (or the equivalent) and that delay results in adjustments to the contract price, or if the scope of the project changes subsequent to execution of the contract. We anticipate that the commissioning cargo proceeds expected to be generated by each project will provide additional contingency that is held at the project-level until certain production milestones are achieved and contingency utilization is replenished.

Following the commencement of operations at our projects, our exposure to market risk for changes in commodity prices will relate primarily to the margin we charge our export customers for feed gas under SPAs. Export customers under our existing SPAs will pay a fee equal to a fixed liquefaction fee (which includes a CPI-linked component) per MMBtu, plus a variable commodity fee per MMBtu, in an amount equal to, depending on the applicable SPA, 115% or more of the Henry Hub gas price, which is intended to cover the price of the feed gas and gas transportation costs and is also intended to cover certain of our operating expenses and partially adjust for inflation. We anticipate that any additional LNG contracts we enter into in the future will similarly require our export customers to pay a fixed liquefaction fee per MMBtu, plus a variable commodity fee per MMBtu, in an amount equal to or higher than 115% of the Henry Hub gas price. As a result, changes in the price of feed gas will impact our operating margins. In addition, there may be differences between the actual price we pay for feed gas and the Henry Hub gas price used to calculate the variable commodity fees under the relevant LNG sales contract. Our operating margins would be affected by any such differences.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Part A — Report of Independent Registered Public Accounting Firm

Our auditors are Ernst & Young LLP. Their PCAOB ID number is 00042.

Part B — Financial statements

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Venture Global, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Venture Global, Inc. (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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						Accounting for Costs of Construction and Development
Description of the Matter						As described in Note 2 to the consolidated financial statements, the Company’s liquefied natural gas (“LNG”) projects are constructed pursuant to the terms of construction and equipment supplier arrangements. Certain of these construction and equipment supplier arrangements contain various terms including retainage, performance bonuses, and liquidated damages that impact the amount and timing of the recognition of the related construction costs. As of December 31, 2025, the Company had capitalized costs, net of accumulated depreciation, of approximately $46.6 billion in Property, plant, and equipment, net. Auditing the Company’s costs of construction involved an increased extent of audit effort to evaluate whether they were recorded consistent with the terms of the construction and equipment supplier agreements and in accordance with accounting principles generally accepted in the United States of America (US GAAP).
How We Addressed the Matter in Our Audit						Our audit procedures included, among others, inspection of a sample of the construction and equipment supplier arrangements, amendments, and change orders to understand the key terms and conditions. We confirmed the terms of the arrangements directly with a sample of the Company’s major construction and equipment suppliers. For a sample of costs recognized under certain projects during the year, we inspected construction reports and other supporting documents and vouched payments to the vendor to test that they were recognized at the correct amount, in the correct period, and were capitalized in accordance with the Company’s accounting policy.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2020.

Tysons, VA

March 2, 2026

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VENTURE GLOBAL, INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share information)


	December 31,
	2025		2024

ASSETS
Current assets
Cash and cash equivalents	$	2,355	$	3,608
Restricted cash	195		169
Accounts receivable	918		364
Inventory, net	253		171
Derivative assets	65		154
Prepaid expenses and other current assets	254		93
Total current assets	4,040		4,559
Property, plant and equipment, net	46,588		34,675
Right-of-use assets	737		602
Noncurrent restricted cash	875		837
Deferred financing costs	543		384
Noncurrent derivative assets	216		1,482
Other noncurrent assets	447		952
TOTAL ASSETS	$	53,446	$	43,491

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	737	$	1,536
Accrued and other liabilities	2,795		1,816
Current portion of long-term debt, net	812		190
Total current liabilities	4,344		3,542
Long-term debt, net	33,393		29,086
Noncurrent operating lease liabilities	696		536
Deferred tax liabilities, net	2,320		1,637
Other noncurrent liabilities	697		794
Total liabilities	41,450		35,595

Commitments and contingencies (Note 15)

Redeemable stock of subsidiary	1,696		1,529
Equity
Venture Global, Inc. stockholders' equity
Class A common stock, par value $0.01 per share (488 million and 2,350 million shares issued and outstanding as of December 31, 2025 and December 31, 2024, respectively)	4		23
Class B common stock, par value $0.01 per share (1,969 million and 0 shares issued and outstanding as of December 31, 2025 and December 31, 2024, respectively)	20		—
Additional paid in capital	2,238		512
Retained earnings	4,720		2,611
Accumulated other comprehensive loss	(239)		(249)
Total Venture Global, Inc. stockholders' equity	6,743		2,897
Non-controlling interests	3,557		3,470
Total equity	10,300		6,367
TOTAL LIABILITIES AND EQUITY	$	53,446	$	43,491

The accompanying notes are an integral part of these consolidated financial statements.

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VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share information)


	Years ended December 31,
		2025		2024		2023

REVENUE		$	13,769	$	4,972	$	7,897

OPERATING EXPENSE
Cost of sales (exclusive of depreciation and amortization shown separately below)		5,920		1,351		1,684
Operating and maintenance expense		975		589		391
General and administrative expense		433		312		224
Development expense		344		635		490
Depreciation and amortization		941		322		277
Insurance recoveries, net		—		—		(19)
Total operating expense		8,613		3,209		3,047

INCOME FROM OPERATIONS		5,156		1,763		4,850

OTHER INCOME (EXPENSE)
Interest income		151		244		172
Interest expense, net		(1,454)		(584)		(641)
Gain (loss) on interest rate swaps		(220)		774		174
Loss on financing transactions		(267)		(14)		(123)
Loss on foreign currency transactions		(3)		—		—
Total other income (expense)		(1,793)		420		(418)

INCOME BEFORE INCOME TAX EXPENSE		3,363		2,183		4,432
Income tax expense		630		437		816
NET INCOME		2,733		1,746		3,616

Less: Net income attributable to redeemable stock of subsidiary		167		144		130
Less: Net income attributable to non-controlling interests		36		59		805
Less: Dividends on VGLNG Series A Preferred Shares		270		68		—
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS		$	2,260	$	1,475	$	2,681

BASIC EARNINGS PER SHARE
Net income attributable to common stockholders per share—basic		$	0.93	$	0.63	$	1.30
Weighted average number of shares of common stock outstanding—basic(a)		2,426		2,350		2,070

DILUTED EARNINGS PER SHARE
Net income attributable to common stockholders per share—diluted		$	0.86	$	0.57	$	1.25
Weighted average number of shares of common stock outstanding—diluted(a)		2,635		2,585		2,143

____________

(a) See Note 20 – Earnings per Share for further discussion regarding the weighted average number of shares of common stock outstanding.

The accompanying notes are an integral part of these consolidated financial statements.

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VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	Years ended December 31,
		2025		2024		2023

NET INCOME		$	2,733	$	1,746	$	3,616
Other comprehensive income
Cash flow hedges, net
Change in fair value, net of income tax benefit of $0, $0 and $2, respectively		—		—		(8)
Reclassification to earnings, net of income tax expense of $4, $3, and $1, respectively		10		11		4
COMPREHENSIVE INCOME		2,743		1,757		3,612
Less: Comprehensive income attributable to redeemable stock of subsidiary		167		144		130
Less: Comprehensive income attributable to non-controlling interests		36		59		803
Less: Dividends on VGLNG Series A Preferred Shares		270		68		—
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS		$	2,270	$	1,486	$	2,679

The accompanying notes are an integral part of these consolidated financial statements.

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VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in millions)


	Stockholders' equity
	Common stock						Members' Capital		Additional paid in capital		Retained earnings		Accumulated other comprehensive loss		Total stockholders' equity		Non-controlling interests
	Class A			Class B
	Shares	Par value		Shares	Par value

BALANCE AT DECEMBER 31, 2022	—	$	—	—	$	—	$	(690)	$	—	$	688	$	(184)	$	(186)	$	695
Net income	—	—		—	—		—		—		2,681		—		2,681		805
Stock-based compensation	—	—		—	—		—		(141)		—		—		(141)		17
Distributions	—	—		—	—		—		—		(149)		—		(149)		(29)
Other comprehensive loss	—	—		—	—		—		—		—		(2)		(2)		(2)
Merger of Legacy VG Partners with Venture Global (the 2023 Merger)	1,969	19		—	—		1,781		152		(1,992)		—		(40)		—
Purchase of non-controlling interests	381	4		—	—		(1,091)		508		—		(74)		(653)		(911)
BALANCE AT DECEMBER 31, 2023	2,350	$	23	—	$	—	$	—	$	519	$	1,228	$	(260)	$	1,510	$	575
Net income	—	—		—	—		—		—		1,543		—		1,543		59
Stock-based compensation	—	—		—	—		—		(7)		—		—		(7)		—
Dividends declared on common stock	—	—		—	—		—		—		(160)		—		(160)		—
Subsidiary distributions	—	—		—	—		—		—		—		—		—		(59)
Other comprehensive income	—	—		—	—		—		—		—		11		11		—
Issuance of VGLNG Series A Preferred Shares, net	—	—		—	—		—		—		—		—		—		2,895
BALANCE AT DECEMBER 31, 2024	2,350	$	23	—	$	—	$	—	$	512	$	2,611	$	(249)	$	2,897	$	3,470
Net income	—	—		—	—		—		—		2,260		—		2,260		306
Stock-based compensation	37	—		—	—		—		57		—		—		57		—
Dividends declared on common stock	—	—		—	—		—		—		(83)		—		(83)		—
Subsidiary distributions	—	—		—	—		—		—		(68)		—		(68)		(219)
Other comprehensive income	—	—		—	—		—		—		—		10		10		—
Conversion of Class A common stock to Class B common stock	(1,969)	(20)		1,969	20		—		—		—		—		—		—
Issuance of Class A common stock, net	70	1		—	—		—		1,669		—		—		1,670		—
BALANCE AT DECEMBER 31, 2025	488	$	4	1,969	$	20	$	—	$	2,238	$	4,720	$	(239)	$	6,743	$	3,557

The accompanying notes are an integral part of these consolidated financial statements.

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VENTURE GLOBAL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Years ended December 31,
	2025		2024		2023

OPERATING ACTIVITIES
Net income	$	2,733	$	1,746	$	3,616
Adjustments to reconcile net income to net cash from operating activities:
(Gain) loss on derivatives, net	342		(777)		(174)
Cash from settlement of derivatives, net	1,252		214		203
Loss on financing transactions	265		15		122
Deferred taxes	638		446		674
Non-cash interest expense	133		76		85
Depreciation and amortization	941		322		277
Stock-based compensation	46		22		28
Changes in operating assets and liabilities:
Accounts receivable	(564)		(90)		(75)
Inventory	(61)		(127)		(18)
Prepaid expenses and other current assets	(10)		(2)		(96)
Accounts payable and accrued liabilities	873		288		(55)
Other, net	(22)		16		(37)
Net cash from operating activities	6,566		2,149		4,550

INVESTING ACTIVITIES
Capital expenditures	(13,365)		(13,717)		(8,091)
Purchase of equity method investments	(19)		(106)		(539)
Other investing activities	164		(336)		(95)
Net cash used by investing activities	(13,220)		(14,159)		(8,725)

FINANCING ACTIVITIES
Issuance of debt and draws on credit facilities	16,329		9,360		16,153
IPO issuance of Class A common stock	1,750		—		—
Issuance of VGLNG Series A Preferred Shares	—		3,000		—
Repayment of debt	(11,071)		(905)		(5,918)
Purchase of non-controlling interests	—		—		(1,564)
Financing and issuance costs	(1,004)		(142)		(591)
Payments of dividends and subsidiary distributions	(465)		(139)		(164)
Financed capital expenditures	(76)		(381)		(108)
Other financing activities	2		(41)		(173)
Net cash from financing activities	5,465		10,752		7,635

Net increase (decrease) in cash, cash equivalents and restricted cash	(1,189)		(1,258)		3,460
Cash, cash equivalents and restricted cash at beginning of period	4,614		5,872		2,412
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	3,425	$	4,614	$	5,872

The accompanying notes are an integral part of these consolidated financial statements.

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - The Company

Venture Global, Inc. is a Delaware corporation formed on September 19, 2023. As used in these consolidated financial statements, unless the context otherwise requires, references to the "Company," "we," "us," and "our" refer to Venture Global, Inc. and its consolidated subsidiaries, whereas references to "Venture Global" refer to Venture Global, Inc., but not its subsidiaries.

The Company is a liquefied natural gas ("LNG") company engaged in the development, construction, ownership, and operation of LNG production facilities and associated infrastructure along the U.S. Gulf Coast. Venture Global's integrated business model spans natural gas supply, transportation, liquefaction, export, shipping and regasification, enabling the Company to deliver LNG to global markets.

The Company currently has multiple LNG projects at varying stages of operation, construction or development. Each LNG project includes a liquefaction facility and export terminal and one or more associated pipelines that interconnect with several interstate and intrastate pipelines for delivery of natural gas into the associated liquefaction facility and export terminal. The Company is also developing expansion, or "bolt-on," projects at existing sites leveraging shared infrastructure under its standardized "design one, build many" development model. Our LNG projects include:


Project Name						Stage of Development

Calcasieu Project						Operating
Plaquemines Project						Construction and Commissioning
Plaquemines Expansion Project						Development
CP2 Project						Construction
CP2 Expansion Project						Development
CP3 Project						Development

The Company is also developing and constructing complementary pipeline systems to support gas transportation for its liquefaction and export projects. In addition, the Company has acquired and operates a fleet of LNG tankers to deliver LNG directly to customers through its sales and shipping business and has secured regasification capacity in key import markets to facilitate downstream sales and enhance its vertically integrated platform.

Note 2 – Summary of Significant Accounting Policies

Basis of presentation and consolidation

The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). The consolidated financial statements include the accounts of Venture Global, Inc. and its controlled subsidiaries. All intercompany transactions and balances have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to current period presentation. Except for per share amounts, or as otherwise specified, dollar amounts presented within tables are stated in millions.

Stock Split

On January 27, 2025, the Company effectuated an approximately 4,520.3317-for-one forward stock split (the "Stock Split") of its Class A common stock in connection with its initial public offering ("IPO") which was

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

completed on January 27, 2025. All Class A common stock share and per share amounts in these consolidated financial statements have been retroactively adjusted to reflect the impact of the Stock Split. See Note 16 – Equity for further discussion of the IPO.

2023 Reorganization Transactions

In September 2023, Venture Global was party to certain reorganization transactions (the "Reorganization Transactions") whereby Venture Global Partners, LLC ("Legacy VG Partners"), a then wholly-owned subsidiary of Venture Global Partners II, LLC ("VG Partners") and controlling shareholder of Venture Global LNG, Inc ("VGLNG"), merged with and into Venture Global (the "2023 Merger"), with VG Partners receiving 2.0 billion shares of Venture Global's Class A common stock, in exchange for 100% of its equity interests in Legacy VG Partners. In connection with the Reorganization Transactions, the non-controlling VGLNG shareholders that held 84,272 shares of VGLNG's issued and outstanding Series C common stock received 381 million shares of Class A common stock of Venture Global, in a 4,520.3317-for-one exchange for their shares of VGLNG (the "NCI Acquisition"). All prior shares of VGLNG common stock were retired upon completion of the Reorganization Transactions in September 2023. No cash was exchanged as part of the Reorganization Transactions and Venture Global incurred $40 million of third-party transaction costs in connection with its formation and the issuance of its shares of Class A common stock.

The 2023 Merger was accounted for as a transaction between entities under common control which represented a change in reporting entity. The NCI Acquisition was accounted for as a change in Venture Global's ownership interest in a subsidiary within equity on a prospective basis. Prior to the 2023 Merger, Venture Global, as a standalone entity, had no operations, and no assets or liabilities. The financial results and other information included in these consolidated financial statements for periods prior to the Reorganization Transactions were applied on a retrospective basis and are reflective of Legacy VG Partners, except for earnings per share. Historical earnings per share was calculated based on the 4,520.3317-for-one exchange ratio of the 2.0 billion shares of Venture Global's Class A common stock issued to VG Partners in exchange for 100% of the Legacy VG Partners equity interests in connection with the 2023 Merger. The shares issued as part of the NCI Acquisition are included in earnings per share prospectively from the date of the Reorganization Transactions. See Note 20 – Earnings per Share for further discussion. The financial results and other information included in these consolidated financial statements for periods prior to the Reorganization Transactions are reflective of Legacy VG Partners, except for earnings per share.

Variable interest entities

Entities in which the Company has variable interest ("VIEs") are consolidated when the Company is determined to be the primary beneficiary. See Note 8 – Equity Method Investments for further discussion.

Use of estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and in the accompanying notes. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Concentration of credit risk

Financial instruments that potentially subject the Company to a concentration of credit risk consist primarily of derivative instruments and accounts receivable related to the Company's LNG sales contracts. Additionally, the Company maintains cash balances at financial institutions which may at times be in excess of federally insured levels. The Company has not incurred credit losses related to these cash balances to date.

The use of derivative instruments exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Exposure to credit risk is limited to the amounts, if any, by

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

which the counterparty's obligations under the derivative contracts exceed the obligations of the Company to the counterparty. The Company mitigates this exposure by minimizing counterparty concentrations, entering into master netting arrangements and generally entering into interest rate swaps with large multinational financial institutions. The Company does not believe there is a material risk of counterparty non-performance.

The Company is dependent on its customers’ creditworthiness and their willingness to perform under their respective agreements. See Note 23 – Segment Information for additional details about the Company's customer concentration.

Fair value measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The carrying values of the Company’s cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued and other liabilities approximate fair value due to their short-term maturities. The Company applies the fair value measurement guidance to financial assets and liabilities included in the cash and cash equivalents, derivative assets, noncurrent derivative assets, accrued and other liabilities and other noncurrent liabilities line items on the consolidated balance sheets. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. In determining fair value, the Company prioritizes the use of observable market data when available. Assets and liabilities are categorized within the fair value hierarchy based upon the lowest level of input that is significant to the fair value measurement:

•Level 1: Quoted prices in active markets for identical assets or liabilities

•Level 2: Inputs other than quoted prices in active markets that are directly or indirectly observable for the asset or liability

•Level 3: Inputs that are not observable in the market

Transfers between Level 2 and Level 3 result from changes in the significance of unobservable inputs used to determine fair value and are recognized as of the beginning of the reporting period in which they occur. For further discussion, see Note 13 – Fair Value Measurements.

Cash and cash equivalents

The Company considers money market funds, commercial paper and all highly liquid investments with original maturities of three months or less at the time of purchase to be cash equivalents.

Restricted cash

The Company holds certain financial instruments that are restricted to withdrawal and use under the terms of certain contractual arrangements. These amounts are presented separately from cash and cash equivalents on the consolidated balance sheets. For further discussion, see Note 3 – Restricted Cash.

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VENTURE GLOBAL, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Revenue recognition

The Company recognizes revenue when it transfers control of promised goods or services to its customers in an amount that reflects the consideration the Company expects to be entitled to receive in exchange for those goods or services. Revenue from the sale of LNG is recognized at the point in time when LNG is delivered to the customer at the agreed upon LNG terminal which is the point when legal title, physical possession, and the risks and rewards of ownership transfer to the customer. Each molecule of LNG is viewed as a separate performance obligation. LNG produced by the Company's facilities is sold to customers on either a free-on-board ("FOB"), delivered-at-place-unloaded ("DPU"), or delivered ex ship ("DES") basis directly from the Company's projects or through its sales and shipping business. When LNG is sold on terms other than FOB, transportation costs incurred by the Company are considered to be fulfillment costs and are not separate performance obligations within the arrangement. The majority of the Company's post-commercial operations date ("COD") SPAs are sold FOB. The stated contract price, including both fixed and variable components, is representative of the stand-alone selling price for LNG at the time the contract was negotiated. Payment terms are within 30 days after the LNG is delivered.

Proceeds from the sale of test LNG generated during the early commissioning of an LNG project ("test LNG sales") are determined based on estimates of LNG production generated from commissioning activities and recognized as a reduction to the cost basis of construction in progress until assets are placed in service in accordance with the accounting guidance.

Accounts receivable

Accounts receivable are reported net of any current expected credit losses. Current expected credit losses consider the risk of loss based on counterparty credit worthiness, past events, current conditions and reasonable and supportable forecasts. There were no allowances for credit losses as of December 31, 2025 or 2024.

Inventory

Inventory consists of LNG inventory, including in-transit, spare parts and materials, and vessel fuel for the Company's LNG tankers and is recognized at the lower of weighted average cost and net realizable value. LNG inventory includes all costs incurred directly for the production of LNG and are recognized as cost of sales, or as part of the cost basis of construction in progress if associated with test LNG sales, when transferred to the customer. Spare parts and materials are charged to operating and maintenance expense as they are consumed.

Property, plant and equipment

Property, plant and equipment are recognized at cost, less accumulated depreciation. Certain assets undergo a commissioning process during which LNG is produced and sold as test LNG. Prior to assets being placed in service in accordance with the accounting guidance, net margin from test LNG sales, including sale proceeds and costs of production, are treated as a reduction of construction in progress. Depreciation is calculated using the straight-line depreciation method over the estimated useful life of the asset. The terminal assets are depreciated on a straight-line basis over the shorter of their estimated useful life or applicable lease terms. Expenditures for construction, acquisition, commissioning activities and costs that significantly extend the useful life or increase the functionality and/or capacity of an asset are capitalized. This includes direct expenditures for planned major maintenance projects such as, but not limited to, planned turbine overhauls performed at defined intervals. Management tests property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable.

Construction in progress

Construction in progress represents the accumulation of project development and construction costs primarily related to the construction of the Company's capital projects. The Company capitalizes project development costs once construction of the relevant project is considered probable. Interest and other related costs incurred on debt obtained for construction of property, plant and equipment are capitalized over the shorter of the construction period

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

or related debt term. Costs incurred for the purchase of major equipment components of probable capital projects are recognized as construction in progress when the Company takes ownership of the equipment. No depreciation expense is recognized on construction in progress until the relevant assets are completed and placed in service in accordance with the accounting guidance.

Advance equipment and construction payments

Advance equipment and construction payments represent amounts paid to suppliers for certain major equipment components of capital projects that have yet to be delivered, advances toward the purchase of an LNG tanker where title of the tanker does not transfer to the Company until the date of delivery, amounts paid to contractors for services not yet performed, and equipment procured prior to a relevant project being deemed probable of construction or completion and that have an alternative use. Under the terms of certain agreements, the Company is required to make payments in accordance with defined milestone payment schedules as related progress milestones are completed by the respective supplier or contractor. The construction and equipment supplier agreements also contain various terms including retainage, performance bonuses, and liquidated damages that impact the amount and timing of the recognition of the related costs. Prior to the Company taking ownership of the asset, payments are capitalized to advance equipment and construction payments at the time consideration is paid or becomes payable. The amounts are transferred to construction in progress once services are performed or the related asset is received or ownership is taken by the Company.

Project development costs

Generally, the costs incurred to develop the Company's projects are treated as development expense until management concludes that construction and completion of the relevant project is probable. These costs primarily include professional fees associated with early engineering and design work, costs of securing necessary regulatory approvals and permits, and other preliminary investigation and development activities related to the projects. Management's probability conclusion for projects is based on factors including, but not limited to, the achievement of, or ability to achieve, certain critical project development milestones, including, where appropriate, receipt of the appropriate regulatory approvals and permits, securing equipment and construction contracts and securing adequate financing arrangements.

Generally, costs that are capitalized during the preliminary stage of development include land acquisition costs, certain environmental credits, leasehold improvement costs necessary for preparing the facilities for their intended use, and direct costs of construction-related activities incurred with third parties. This includes costs that are directly identifiable for the early procurement of equipment that is probable of being acquired prior to a relevant project being deemed probable of construction or completion and that has an alternative use.

For further discussion of the Company's property, plant and equipment, see Note 6 – Property, Plant and Equipment.

Leases

The Company determines if an arrangement is, or contains, a lease at its inception. When an arrangement is, or contains, a lease, the Company classifies the lease as either an operating or finance lease. Operating and finance leases are recognized on the consolidated balance sheets as lease liabilities, representing the obligation to make future lease payments, and right-of-use assets, representing the right to use the underlying assets for the lease term. Operating and finance lease liabilities and right-of-use assets are generally recognized based on the present value of lease payments over the lease term. In determining the present value of lease payments, the Company uses the implicit interest rate in the lease, if readily determinable. In the absence of a readily determinable implicit interest rate, the Company discounts its expected future lease payments using the lessee's incremental borrowing rate. The incremental borrowing rate is an estimate of the interest rate that a lessee would have to pay to borrow on a collateralized basis over a similar term to that of the lease term. Lease and non-lease components of the Company's marine vessels are combined in calculating the right-of-use asset and lease liability. Options to renew a lease are included in the lease term and recognized as a part of the right-of-use asset and lease liability only to the extent they

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are reasonably certain to be exercised. Adjustments to lease payments due to changes in a variable index are treated as variable lease costs and recognized in the period in which they are incurred.

Operating lease expense is recognized on a straight-line basis over the lease term. Finance lease expense is recognized as amortization of the right-of-use assets on a straight-line basis and interest on lease liabilities using the effective interest method over the lease term. Leases with an initial term of 12 months or less are not recognized on the consolidated balance sheets and are expensed on a straight-line basis. For further discussion, see Note 7 – Leases.

Deferred financing costs

Deferred financing costs represent debt issuance costs incurred in connection with working capital facilities and term loans which have not yet been fully drawn. Deferred financing costs are amortized on a straight-line basis to interest expense over the availability period of the working capital facility or undrawn term loans. Once a term loan is fully drawn, its associated unamortized deferred financing costs are reclassified to a contra-liability in long-term debt, net on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the remaining term of the debt.

Equity method investments

Investments in entities in which the Company has the ability to exercise significant influence over operating and financial policies, but not control, are accounted for using the equity method of accounting. In applying the equity method of accounting, investments are initially recognized at cost, and subsequently adjusted for the Company's proportionate share of earnings, losses and distributions. These investments are recognized within other noncurrent assets on the Company's consolidated balance sheets. For further discussion, see Note 8 – Equity Method Investments.

Rights-of-way

The Company obtains perpetual rights to construct, operate and maintain its pipelines on land owned or bodies of water controlled by third parties. The costs to obtain these rights are capitalized as indefinite-lived intangible assets in other noncurrent assets on the consolidated balance sheets. No amortization is recognized on these assets, as the rights-of-way are perpetual in nature.

Derivative instruments

The Company reflects all contracts that meet the definition of a derivative, except those designated and qualifying as normal purchase normal sale ("NPNS"), as either assets or liabilities on the consolidated balance sheets at fair value. Changes in the fair value of derivative instruments are recognized in earnings as cost of sales, development expense, or gain (loss) on interest rate swaps, unless the Company elects to apply hedge accounting and meets the specified criteria in ASC 815, Derivatives and Hedging. The Company designates derivative instruments as cash flow hedges based on all available facts and circumstances.

The Company enters into interest rate swap agreements to mitigate volatility arising from changes in interest rates and enters into natural gas forward purchase contracts for the supply of feed gas to its projects ("natural gas supply contracts"). The Company does not utilize derivatives for trading or speculative purposes. Derivative instruments are recognized at fair value on the consolidated balance sheets.

Changes in fair value of derivative instruments designated as cash flow hedges are recognized in accumulated other comprehensive loss ("AOCL") until the hedged transaction affects earnings, at which time the deferred gains and losses are reclassified to earnings. Cash flows of the Company's derivatives which are not designated as hedging relationships are classified as operating activities in the consolidated statements of cash flows unless the derivatives contain an other-than-insignificant financing element at inception, in which case the associated cash flows are classified as financing activities. Derivative assets and liabilities are presented net on the consolidated

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balance sheets when a legally enforceable master netting arrangement exists with the counterparty. For further discussion, see Note 12 – Derivatives.

The Company discontinues hedge accounting on a prospective basis if the derivative is no longer expected to be highly effective as a hedge, if the hedged transaction is no longer probable of occurring, or if the Company de-designates the instrument as a cash flow hedge. Any gain or loss in AOCL at the time of de-designation is reclassified into earnings in the same period the hedged transaction affects earnings unless the underlying hedged transaction is probable of not occurring, in which case, any gain or loss in AOCL is reclassified into earnings immediately.

The Company evaluates all of its financial instruments to determine if such instruments are freestanding derivatives or if they contain features that qualify as embedded derivatives. If an instrument contains more than one embedded feature that warrants separate accounting, those embedded features are bundled together as a single, compound embedded derivative that is bifurcated and accounted for separately from the host contract.

Accounts payable and accrued and other liabilities

The Company recognizes invoiced amounts from operating and construction vendors as accounts payable on the consolidated balance sheets. Accrued and other liabilities on the consolidated balance sheets primarily represent amounts owed to the Company's vendors but not yet invoiced, accrued interest, accrued compensation costs and accrued dividends and distributions. For further discussion, see Note 9 – Accrued and Other Liabilities.

Asset retirement obligations ("ARO")

The Company recognizes a liability at fair value for an ARO when the legal obligation to retire the asset has been incurred (i.e., as the asset is being constructed) and a reasonable estimate of fair value can be made. The ARO liability is classified as other noncurrent liabilities on the consolidated balance sheets with a corresponding increase to the carrying amount of the related long-lived asset. AROs are periodically adjusted to reflect changes in the estimated present value of the obligation resulting from revisions to the estimated timing or amount of the expected future cash flows. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss. For further discussion, see Note 10 – Asset Retirement Obligations.

Redeemable stock of subsidiary

Redeemable stock of subsidiary on the consolidated balance sheets represents third-party interests in the net assets of the Company's subsidiary, Calcasieu Pass Funding, LLC ("Calcasieu Funding"), resulting from the issuance of the CP Funding Redeemable Preferred Units, as discussed and defined in Note 17 – Redeemable Stock of Subsidiary. The third-party has the right to redeem its interests for cash upon the occurrence of events not solely within the Company's control and therefore the redeemable stock of subsidiary is classified outside of permanent equity, as mezzanine equity, on the consolidated balance sheets. The balance is carried at its current redemption value as adjusted by the contractually stated distribution amount that is recognized in each reporting period as net income attributable to redeemable stock of subsidiary on the consolidated statements of operations.

Non-controlling interests

Non-controlling interests on the consolidated balance sheets represent the portion of net assets in consolidated subsidiaries that are not owned by the Company. Non-controlling interests are recognized as a separate component of equity on the consolidated balance sheets and are adjusted, as applicable, by the amount of earnings or other comprehensive income (loss) attributable to the non-controlling interests, distributions, and changes in ownership interest. A change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and non-controlling interests. Losses are attributed to the non-controlling interests even when the non-controlling interests’ basis has been reduced to zero. For further discussion, see Note 18 – Non-Controlling Interests.

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Operating expenses

Cost of sales is comprised of the direct costs associated with the production of LNG that is recognized as revenue. It includes the cost of purchasing and transporting natural gas used in the production of LNG, also known as feed gas, and excludes depreciation and amortization, shown separately on the consolidated statements of operations. Cost of sales also includes changes in the fair value of certain of the Company's natural gas supply contracts that are recognized as derivative instruments and are outstanding after an LNG facility starts producing LNG.

Operating and maintenance expense primarily includes non-capitalizable costs directly related to the operation and maintenance of the Company's projects, including personnel costs, the cost of spares and consumables used in maintenance, land lease expense, ARO accretion expense, certain legal costs and project-related information technology costs. Operating and maintenance expense also includes costs associated with operating the Company's LNG tankers including maintenance costs, fuel, and costs to crew the tankers. Expenditures for maintenance and repairs—excluding those for planned major maintenance projects—are generally expensed as incurred.

General and administrative expense primarily includes costs not directly associated with the operations or development of the Company's projects, such as the Company's corporate support functions including executive management, information technology (except for direct project-related IT costs that are included in operating and maintenance expense), human resources, legal, and finance.

Development expense primarily includes costs incurred to develop a project prior to management's conclusion that construction and completion of the relevant project is probable and that are not otherwise recoverable through other projects or resale. These expenses consist primarily of engineering and design expenses and other development and construction related costs to the extent such expenditures do not meet the criteria for capitalization. Development expense also includes changes in the fair value of certain natural gas supply contracts recognized as derivative instruments that are outstanding prior to first LNG production at a facility.

Stock-based compensation

The Company accounts for stock-based compensation using the fair value method. The grant-date fair value attributable to stock options is calculated based on the Black-Scholes option-pricing model and is amortized on a straight-line basis to expense over the vesting period of the award. Forfeitures are recognized as they occur. For further discussion, see Note 19 – Stock-Based Compensation.

Income taxes

The Company is treated as a corporation for income tax purposes. Prior to the Reorganization Transactions, the Company was treated as a partnership for income tax purposes. The change in the tax status of the Company did not have a material impact on its income taxes.

The Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred income tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, the Company determines income tax assets and liabilities based on the differences between the financial statement and income tax basis for assets and liabilities using the enacted statutory tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rate on deferred income tax assets and liabilities is recognized in income in the period that includes the enactment date. The Company’s accounting policy for releasing the income tax effects from AOCL occurs on a portfolio basis.

A valuation allowance is provided for deferred income taxes if it is more-likely-than-not these items will either expire before the Company is able to realize their benefits or if future deductibility is uncertain. Additionally, the Company evaluates tax positions under a more-likely-than-not recognition threshold and measurement analysis

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before the positions are recognized for financial statement reporting. For further discussion, see Note 14 – Income Taxes.

Earnings per share

Basic net income per share is computed by dividing net income attributable to common stockholders by the weighted-average number of shares of common stock outstanding during the period. Diluted net income per share is computed by giving effect to all potentially dilutive securities, including stock options outstanding. For further discussion, see Note 20 – Earnings per Share.

Note 3 – Restricted Cash

The following table summarizes the components of restricted cash:


	December 31,
	2025		2024

Current restricted cash
Debt service reserves	$	121	$	141
Other project reserves	74		28
Total current restricted cash	$	195	$	169

Noncurrent restricted cash
Construction reserves	$	770	$	611
Debt service reserves	105		226
Total noncurrent restricted cash	$	875	$	837

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the consolidated statements of cash flows:


	December 31,
	2025		2024

Cash and cash equivalents	$	2,355	$	3,608
Current restricted cash	195		169
Noncurrent restricted cash	875		837
Cash, cash equivalents, and restricted cash per the consolidated statements of cash flows	$	3,425	$	4,614

Note 4 – Revenue from Contracts with Customers

The Company has entered into numerous contracts for the sale of LNG to third-party customers. LNG produced by our facilities is sold to the Company's customers directly from our projects or through our sales and shipping business on either a FOB, DPU or DES basis. The LNG sales price structure under the Company's sales agreements generally includes (i) a fixed liquefaction fee, a portion of which is subject to an annual adjustment for inflation; (ii) a variable commodity fee equal to at least 115% of Henry Hub per million British thermal units ("MMBtu"); and (iii) a transportation charge, if sold on a DPU basis. Some of the Company's DES sales agreements are structured with a single sales price that includes transportation and is indexed to foreign gas markets, such as Title Transfer Facility index ("TTF") or Japan Korea Marker index ("JKM").

The fixed liquefaction fee component under the Company's LNG sales agreements is the amount owed to the Company regardless of a cancellation or suspension of LNG cargo deliveries by its customers. The variable commodity fee component is the amount generally payable to the Company only upon delivery of LNG. The Company's LNG sales agreements include provisions for contingent payments for non-performance, delays, or other damages, which may be due from the Company, and represent variable consideration. Any estimates for contingent

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payments are based on either the Company's best estimate of the most likely outcome or the expected value, depending on which method best predicts the total net consideration to which the Company will be entitled over the term of the LNG sales agreement. Payments, and estimates for contingent payments, made by the Company are recognized as a reduction to the transaction price (as an adjustment to the fixed liquefaction fee) as LNG is delivered to customers over the term of the LNG sales agreement.

Liabilities associated with estimates for contingent payments are limited to any rights to payment from customers (i.e., for satisfied performance obligations) that are in excess of the recognized transaction price until the uncertainty around the obligation, including its value, is resolved. A liability is not recognized for estimates of contingent payments until the earlier of when consideration received from a customer exceeds the transaction price allocated to satisfied performance obligations, or a contingent payment becomes a fixed financial obligation.

LNG produced prior to the relevant project, or phase thereof, reaching COD is sold under short- or mid-term LNG commissioning sales agreements at prevailing market or forward prices when executed. The majority of LNG produced after the relevant project, or phase thereof, reaching COD will be sold under long-term 20-year post-COD SPAs.

On April 15, 2025, the Calcasieu Project declared COD and commenced the sale of LNG to its customers under its post-COD SPAs. The Calcasieu Project post-COD SPAs are delivered on a FOB basis, which means that the title to the LNG transfers at the time customers take delivery at the project's facility.

The following table summarizes the disaggregation of revenue earned from contracts with customers:


	Years ended December 31,
		2025		2024		2023

LNG revenue		$	13,687	$	4,947	$	7,875
Other revenue		82		25		22
Total revenue		$	13,769	$	4,972	$	7,897

Transaction price allocated to future performance obligations

Because many of the Company's sales contracts have long-term durations, the Company is contractually entitled to significant future consideration which it has not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price, including variable consideration, that is allocated to performance obligations for legally enforceable sales agreements that have not yet been satisfied, excluding all performance obligations of contracts that have an expected duration of one year or less (dollar amounts in billions):


	December 31, 2025
	Unsatisfied transaction price(a)		Weighted average recognition timing (in years)

LNG revenue	$	299.5	19.6 years

_____________

(a) A portion of the transaction price is based on the forecasted Henry Hub index as of December 31, 2025.

Significant judgments were made when estimating the transaction price allocated to future performance obligations. These include i) the best estimate of when the Company's respective projects will reach COD and the post-COD SPAs will commence, which is currently expected to occur in 2026 and 2027 for Phases 1 and 2 of the Plaquemines Project, respectively, and 2029 for Phase 1 of the CP2 Project, and ii) reductions to the transaction price to reflect management's best estimate of variable consideration. This variable consideration relates to the four pending disputes with Calcasieu Project post-COD SPA customers who are asserting that the Calcasieu Project was delayed in declaring COD under the respective post-COD SPAs.

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In October 2025, a partial final award was issued in the arbitration proceedings with BP Gas Marketing Limited (“BP”). Remedies were not addressed in the partial final award and will be determined in a separate damages hearing. A final award is expected to be issued following the damages portion of the hearing. Based on the terms of the partial final award, the Company does not anticipate that the final award will be subject to the seller aggregate liability limitation in the BP post-COD SPA. The remedies sought by BP include damages ranging from $3.7 billion to potentially in excess of $6.0 billion, as well as interest, costs and attorneys’ fees. The Company believes BP’s theory and calculations of damages are without merit and that the magnitude of damages sought by BP is not recoverable under the express terms of the post-COD SPA, which include express limits on the tribunal’s jurisdictional authority, although there can be no assurance as to the outcome of the damages portion of the hearing.

Three of the Calcasieu Project's other customers are disputing whether the liability limitations in the Company's post-COD SPAs are applicable, and therefore are claiming damages, including amounts in excess of the liability limitations. The Company believes the disputes with these other customers are subject to the aggregate liability limitations of $595 million under the applicable post-COD SPAs.

Note 5 – Inventory

The following table summarizes the components of inventory:


	December 31,
	2025		2024

Spare parts and materials	$	159	$	89
LNG	56		36
LNG in-transit	24		36
Other	14		10
Total inventory, net	$	253	$	171

Note 6 – Property, Plant and Equipment

The following table presents the components of property, plant and equipment, net and their estimated useful lives (in years):


		December 31,
	Estimated useful life	2025		2024

Terminal and interconnected pipeline facilities(a)	7-48	$	32,651	$	18,698
Construction in progress	N/A	7,641		10,773
Advanced equipment and construction payments	N/A	5,541		4,733
LNG tankers	25	1,780		630
Other(b)	2-35	711		633
Total property, plant and equipment at cost		48,324		35,467
Accumulated depreciation		(1,736)		(792)
Total property, plant and equipment, net		$	46,588	$	34,675

____________

(a) During the year ended December 31, 2025, the Company determined that it was reasonably certain to exercise certain options to renew various land leases thereby extending the remaining lease terms and therefore extended the estimated useful lives of the terminal assets previously constrained by the terms of the land lease to which they are affixed. This resulted in a $185 million reduction to depreciation expense, or $0.08 and $0.07 increase in basic and diluted earnings per share, respectively, for the year ended December 31, 2025. See Note 7 – Leases for further discussion.

(b) Includes finance lease assets, buildings, and land, which does not depreciate. See Note 7 – Leases for further discussion.

During the year ended December 31, 2025, the CP2 Project was deemed probable of construction and completion. Subsequent costs associated with the development and construction of the terminal and associated

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pipeline, including capitalizable interest, have been capitalized as construction in progress or advanced equipment payments.

In May 2025 and July 2025, the Company acquired the remaining equity ownership interests in Kagami 1 and Kagami 2, respectively. These purchases were recognized prospectively as asset acquisitions of the LNG tankers named Venture Acadia and Venture Creole, respectively. See Note 8 – Equity Method Investments for further discussion.

During the year ended December 31, 2025, the Company recognized $69 million of net proceeds, after deducting the cost of feed gas, from Test LNG sales as a reduction to the cost basis of the Plaquemines Project LNG terminal.

As of December 31, 2025, $24.9 billion, which represents a portion of the Plaquemines Project's property, plant and equipment, has been placed in service in accordance with the applicable accounting guidance. The Plaquemines Project remains under construction and is undergoing its planned commissioning program to satisfy the requirements necessary for achieving commercial operations as defined under the applicable contracts. Costs associated with these efforts are either capitalized or expensed in accordance with the applicable accounting guidance.

As of December 31, 2025, and 2024, the Company had $209 million and $145 million, respectively, of costs associated with perpetual rights of way used to construct, operate, and maintain its pipelines. These rights are capitalized as indefinite-lived intangible assets in other noncurrent assets on the consolidated balance sheets.

The following table presents depreciation expense recognized on the consolidated statements of operations:


	Years ended December 31,
		2025		2024		2023

Depreciation expense		$	930	$	316	$	273

Note 7 – Leases

Operating leases consist primarily of leased land, LNG tankers, and office space and facilities. Finance leases consist primarily of leased marine vessels and a bridge.

During the year ended December 31, 2025, the Company determined that it was reasonably certain to exercise certain options to renew various land leases thereby extending the remaining lease terms. This was recognized as a lease modification and resulted in an increase in right-of-use assets in exchange for operating lease liabilities of $88 million.

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The following table presents the line item classification of right-of-use assets and lease liabilities on the consolidated balance sheets:


		December 31,
	Line item	2025		2024

Right-of-use assets—operating	Right-of-use assets	$	737	$	602
Right-of-use assets—finance	Property, plant and equipment, net	286		279
Total right-of-use assets		$	1,023	$	881

Current operating lease liabilities	Accrued and other liabilities	$	62	$	81
Current finance lease liabilities	Accrued and other liabilities	9		10
Noncurrent operating lease liabilities	Noncurrent operating lease liabilities	696		536
Noncurrent finance lease liabilities	Other noncurrent liabilities	249		248
Total lease liabilities		$	1,016	$	875

The Company's lease costs are presented in various line items consistent with the underlying nature of the lease. The following table presents the components of total lease costs included in the consolidated statements of operations.


	Years ended December 31,
		2025		2024		2023

Operating lease cost		$	133	$	97	$	49
Finance lease cost		36		29		17
Total lease cost		$	169	$	126	$	66

Future annual minimum lease payments for operating and finance leases as of December 31, 2025 are as follows:


Years ended December 31,	Operating leases		Finance leases

2026	$	106	$	30
2027	76		27
2028	55		26
2029	56		26
2030	55		26
Thereafter	2,262		400
Total lease payments	$	2,610	$	535
Less: Interest	(1,852)		(277)
Present value of lease liabilities	$	758	$	258

The following table presents the weighted-average remaining lease term (in years) and the weighted-average discount rate for the Company's operating leases and finance leases:


	December 31,
	2025		2024
	Operating leases	Finance leases	Operating leases	Finance leases

Weighted-average remaining lease term	31.6	20.3	19.2	20.9
Weighted-average discount rate	7.7%	8.4%	7.8%	8.6%

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Note 8 – Equity Method Investments

The following table presents equity method investment ownership interests and carrying values:


	December 31, 2024
Equity method investment	Ownership interest	Carrying value

Kagami 1	39%	$	164
Kagami 2	39%	163
Total		$	327

Kagami Companies

In 2023, the Company began acquiring equity interests in Project Kagami 1 Limited ("Kagami 1") and Project Kagami 2 Limited ("Kagami 2", and together with Kagami 1, the "Kagami Companies"). The Kagami Companies each purchased one LNG tanker. The equity method investments were recognized within other noncurrent assets and held by the sales and shipping reportable segment.

In May 2025 and July 2025, the Company completed the acquisitions of the full equity ownership interests in Kagami 1 and Kagami 2, respectively, through a series of transactions, for a total purchase price of $540 million. Prior to the acquisitions, Kagami 1 and Kagami 2 were variable interest entities in which the Company was not the primary beneficiary since it lacked the power to make significant decisions, and were accordingly recognized as equity method investments. As of December 31, 2025, the LNG tankers held by Kagami 1 and Kagami 2 are recognized as property, plant and equipment. See Note 6 – Property, Plant and Equipment for further discussion.

Note 9 – Accrued and Other Liabilities

Components of accrued and other liabilities included:


	December 31,
	2025		2024

Accrued construction and equipment costs	$	819	$	620
Accrued interest	534		361
Accrued natural gas purchases	892		267
Accrued compensation	232		191
Derivative liabilities	104		13
Accrued dividends and distributions	—		95
Other	214		269
Total accrued and other liabilities	$	2,795	$	1,816

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Note 10 – Asset Retirement Obligations

The following table summarizes the components of the Company's asset retirement obligations:


	Years ended December 31,
	2025		2024

Beginning balance as of January 1	$	502	$	411
Liabilities incurred	22		63
Accretion expense	23		28
Revision in the timing of estimated cash flows(a)	(339)		—
Ending balance as of December 31	$	208	$	502

_____________

(a)During the year ended December 31, 2025, the Company determined that it was reasonably certain to exercise certain options to renew various land leases thereby extending the remaining lease terms. In connection with the extension, the Company revised the estimated settlement dates for certain asset retirement obligations.

Note 11 – Debt

The following table summarizes outstanding debt:


			December 31,
	Maturity	Weighted average interest rate	2025		2024

Fixed rate:
VGLNG Senior Secured Notes	2028 - 2032	8.716%	$	11,000	$	11,000
VGCP Senior Secured Notes	2029 - 2033	4.441%	4,750		4,750
VGPL Senior Secured Notes	2030 - 2036	6.780%	9,500		—
Other fixed rate debt(a)	2029	7.600%	84		84
Variable rate:
Calcasieu Pass Credit Facilities	2026		806		997
Plaquemines Credit Facilities	2029		2,683		12,720
CP2 Credit Facilities	2032		1,860		—
CP2 Holdings EBL Facilities	2028		3,000		—
Blackfin Credit Facilities	2030 - 2032		1,129		—
Total outstanding debt			34,812		29,551
Less: Unamortized debt discount, premium and issuance costs			(607)		(275)
Total outstanding debt, net			34,205		29,276
Less: Current portion of long-term debt, net			(812)		(190)
Total long-term debt, net			$	33,393	$	29,086

____________

(a)Secured by a first priority interest in corporate property.

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The aggregate contractual annual maturities for outstanding debt as of December 31, 2025 are as follows:


Years ended December 31,	Contractual maturities

2026	$	817
2027	310
2028	5,502
2029	6,491
2030	4,364
Thereafter	17,328
Total	$	34,812

Fixed rate debt

VGLNG Senior Secured Notes

The VGLNG Senior Secured Notes are secured on a pari passu basis by a first-priority security interest in substantially all of the existing and future assets of VGLNG and the future guarantors, if any. In addition, VGLNG has pledged its membership interests in certain material direct subsidiaries as collateral to secure its obligations under the VGLNG Senior Secured Notes. VGLNG may redeem all or part of the VGLNG Senior Secured Notes at specified prices set forth in the respective governing indenture, plus accrued interest, if any, as of the date of the redemption.

VGCP Senior Secured Notes

The obligations of Venture Global Calcasieu Pass, LLC ("VGCP") under the VGCP Senior Secured Notes are guaranteed by TransCameron Pipeline, LLC ("TCP") and secured on a pari passu basis by a first-priority security interest in the assets that secure the Calcasieu Pass Credit Facilities. VGCP may redeem all or part of the VGCP Senior Secured Notes at specified prices set forth in the respective governing indenture, plus accrued interest, if any, as of the date of the redemption.

VGPL Senior Secured Notes

In April 2025, Venture Global Plaquemines LNG, LLC ("VGPL") issued $2.5 billion aggregate principal amount of senior secured notes, which were issued in two series: (i) a series of 7.500% senior secured notes due 2033 in an aggregate principal amount of $1.25 billion (the "VGPL 2033 Notes") and (ii) a series of 7.750% senior secured notes due 2035 in an aggregate amount of $1.25 billion ("the VGPL 2035 Notes"). In July 2025, VGPL issued $4.0 billion aggregate principal amount of senior secured notes, which were issued in two series: (i) a series of 6.500% senior secured notes due 2034 in an aggregate principal amount of $2.0 billion (the “VGPL January 2034 Notes”) and (ii) a series of 6.750% senior secured notes due 2036 in an aggregate principal amount of $2.0 billion (the “VGPL 2036 Notes”). In December 2025, VGPL issued $3.0 billion aggregate principal amount of senior secured notes, which were issued in two series: (i) a series of 6.125% senior secured notes due 2030 in an aggregate of $1.75 billion (the "VGPL 2030 Notes") and (ii) a series of 6.500% VGPL 2034 Notes in an aggregate of $1.25 billion (the "VGPL June 2034 Notes"). In connection with the issuances of the VGPL Senior Secured Notes, VGPL incurred cumulative debt issuance costs of $187 million primarily related to lender fees which will be amortized over the term of the notes.

In connection with the issuances of the VGPL Senior Secured Notes, VGPL settled a pro rata portion of its interest rate swaps that hedged the variable interest on the Plaquemines Credit Facilities for cash proceeds of $1.1 billion. See Note 12 – Derivatives for further discussion. The proceeds from the issuances of the VGPL Senior Secured Notes and the swap breakage proceeds were used to prepay $10.4 billion outstanding under the Plaquemines Construction Term Loan and to pay costs incurred in connection with the offerings. The prepayments

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were accounted for as partial debt extinguishments resulting in a $226 million loss on financing transactions during the year ended December 31, 2025.

The obligations of VGPL under the VGPL Senior Secured Notes are guaranteed by Venture Global Gator Express, LLC ("Gator Express") and secured on a pari passu basis by a first-priority security interest in the assets that secure the Plaquemines Credit Facilities. VGPL may redeem all or part of the VGPL Senior Secured Notes at specified prices set forth in the respective governing indenture, plus accrued interest, if any, as of the date of the redemption.

Variable rate debt — LNG projects

Below is a summary of committed credit facilities outstanding for our LNG projects as of December 31, 2025:


	Calcasieu Pass Credit Facilities(a)				Plaquemines Credit Facilities(b)				CP2 Credit Facilities(c)
	Calcasieu Pass Construction Term Loan		Calcasieu Pass Working Capital Facility		Plaquemines Construction Term Loan		Plaquemines Working Capital Facility		CP2 Construction Term Loan		CP2 Working Capital Facility		CP2 Holdings EBL Facilities(d)

Total commitments	$	5,477	$	555	$	12,948	$	2,100	$	11,250	$	850	$	3,000

Less:
Outstanding balances	806		—		2,529		154		1,860		—		3,000
Commitments prepaid or terminated	4,671		—		10,419		—		—		—		—
Letters of credit issued	—		276		—		1,309		—		110		—
Available commitments	$	—	$	279	$	—	$	637	$	9,390	$	740	$	—

Priority ranking	Senior secured		Senior secured		Senior secured		Senior secured		Senior secured		Senior secured		Senior secured
Interest rate on outstanding balances	SOFR +		SOFR +		SOFR +		SOFR +		SOFR +		SOFR +		SOFR +
	2.475% to 2.975%		2.475% to 2.975%		1.975% to 2.625%		1.975% to 2.625%		2.250% to 2.750%		2.250% to 2.750%		3.500%
	or		or		or		or		or		or		or
	base rate +		base rate +		base rate +		base rate +		base rate +		base rate +		base rate +
	1.375% to 1.875%		1.375% to 1.875%		0.875% to 1.375%		0.875% to 1.375%		1.250% to 1.750%		1.250% to 1.750%		2.500%
Commitment fees on undrawn balance	0.831% to 1.006%		0.831% to 1.006%		0.656% to 0.831%		0.656% to 0.831%		0.788% to 0.963%		0.788% to 0.963%		N/A

____________

(a)The obligations of VGCP as the borrower are guaranteed by TCP and secured by a first-priority lien on substantially all of the assets of VGCP and TCP, as well as all of the membership interests in those companies.

(b)The obligations of VGPL as the borrower are guaranteed by Gator Express and secured by a first-priority lien on substantially all of the assets of VGPL and Gator Express, as well as all of the membership interests in those companies.

(c)The obligations of CP2 as the borrower are guaranteed by CP2 Procurement and CP Express and secured by a first-priority lien on substantially all of the assets of CP2, CP2 Procurement and CP Express, as well as all of the membership interests in those companies.

(d)CP2 Holdings as the borrower has pledged all its assets as collateral to secure its obligations under the CP2 Holdings EBL Facilities.

CP2 Bridge Facilities

In May 2025, Venture Global CP2 LNG, LLC ("CP2") as borrower, and CP2 Procurement, LLC ("CP2 Procurement") and Venture Global CP Express, LLC ("CP Express") as guarantors, entered into the $3.0 billion CP2 Bridge Facilities, consisting of a $2.8 billion delayed draw bridge loan facility (the "CP2 Bridge Loan Facility") and a $175 million interest reserve facility (the "CP2 Interest Reserve Facility"). Borrowings under the CP2 Bridge Facilities bear interest at a set margin rate over the debt term, plus, at the Company's election, either a SOFR or base

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rate. The set margin rate for SOFR-based loans is 3.500% and the set margin rate for base rate loans is 2.500%. The Company also incurred commitment fees of 35% of the set margin rate on the undrawn available commitments of the CP2 Bridge Facilities. In connection with the issuance of the CP2 Bridge Facilities, CP2 incurred debt issuance costs of $95 million primarily related to lender fees which will be amortized over the term of the credit facility.

In July 2025, the Company prepaid in full the $1.1 billion outstanding balance under the CP2 Bridge Facilities using proceeds from the CP2 Holdings EBL Facilities entered into in connection with FID for Phase 1 of the CP2 Project, discussed below. Of the total prepayment, $308 million was accounted for as a debt extinguishment and $777 million was accounted for as a debt modification. This resulted in the write-off of $25 million of previously capitalized deferred issuance costs and $16 million in fees paid to the extinguished lenders recognized as loss on financing transactions in the consolidated statements of operations during the year ended December 31, 2025.

FID for Phase 1 of the CP2 Project

In July 2025, Phase 1 of the CP2 Project achieved FID and the Company obtained $15.1 billion in project financing. The Company, through its subsidiary CP2 Holdings, entered into the $3.0 billion CP2 Holdings EBL Facilities. Furthermore, CP2, as borrower, and CP2 Procurement and CP Express, as guarantors, entered into the $12.1 billion aggregate senior secured CP2 Credit Facilities. Additional details regarding these transactions follows.

CP2 Holdings EBL Facilities

In July 2025, CP2 LNG Holdings, LLC ("CP2 Holdings"), as borrower, entered into $3.0 billion aggregate secured credit facilities, consisting of a $2.8 billion secured equity bridge credit facility (the “CP2 Equity Bridge Facility”) and a $191 million three-year secured interest reserve credit facility (the “CP2 Interest Reserve Facility”, and together with the CP2 Equity Bridge Facility, the "CP2 Holdings EBL Facilities"). In connection with the issuance of the CP2 Holdings EBL Facilities, CP2 Holdings incurred debt issuance costs of $95 million primarily related to new and modified lender fees which are amortized over the term of the credit facility. A portion of the proceeds from the project financing was used to prepay the outstanding CP2 Bridge Facilities in full and pay costs incurred in connection with the project financing. The remaining proceeds from the project financing will be used to fund the costs of financing, developing, constructing, and placing in service Phase 1 of the CP2 Project.

The CP2 Holdings EBL Facilities are subject to mandatory prepayment provisions, including provisions which would require prepayment with the proceeds of additional indebtedness or prepayment upon receipt of certain net proceeds from the sale of commissioning cargos generated by the Plaquemines Project. The CP2 Holdings EBL Facilities can be voluntarily prepaid at any time without premium or penalty.

CP2 Credit Facilities

In July 2025, CP2, as borrower, and CP2 Procurement and CP Express, as guarantors, entered into $12.1 billion aggregate senior secured credit facilities, consisting of the $11.3 billion CP2 Construction Term Loan and the $850 million CP2 Working Capital Facility. In connection with the issuance of the CP2 Credit Facilities, CP2 incurred debt issuance costs of $460 million primarily related to lender fees which are amortized over the term of the credit facility. Proceeds from the CP2 Credit Facilities will be used to fund the costs of financing, developing, constructing, and placing in service Phase 1 of the CP2 Project.

The CP2 Credit Facilities can be voluntarily prepaid at any time without premium or penalty.

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Variable rate debt — pipeline infrastructure projects

Below is a summary of committed credit facilities outstanding for the Company's pipeline infrastructure projects as of December 31, 2025:

Blackfin Credit Facilities(a)

Blackfin TLA Facility

Blackfin TLB Facility

Blackfin Working Capital Facility

Total commitments

425

1,075

Less:

Outstanding balances

1,075

—

Available commitments

371

—

Priority ranking

Senior secured

Interest rate on outstanding balances

SOFR + 2.250% to 2.500%

SOFR + 3.000%

SOFR + 2.250% to 2.500%

base rate + 1.250% to 1.500%

base rate + 2.000%

base rate + 1.250% to 1.500%

Commitment fees on undrawn balance

0.438% to 0.875%

N/A

0.438% to 0.875%

____________

(a)Blackfin, as borrower, has pledged all its assets as collateral to secure its obligations under the Blackfin Credit Facilities.

Blackfin Credit Facilities

In September 2025, Blackfin Pipeline, LLC ("Blackfin"), as borrower, entered into $1.6 billion aggregate senior secured facilities, consisting of a $1.1 billion secured term loan facility (the "Blackfin TLB Facility") and a $425 million secured construction term loan facility (the "Blackfin TLA Facility") and a $75 million secured revolving loan and letter of credit facility (the "Blackfin Working Capital Facility", and together with the Blackfin TLA Facility and the Blackfin TLB Facility, the "Blackfin Credit Facilities"). In October 2025, the Company increased the commitment under the Blackfin TLB Facility by $25 million. In connection with the issuance of the Blackfin Credit Facilities, Blackfin incurred debt issuance costs of $41 million primarily related to lender fees which will be amortized over the term of the credit facility. Proceeds from the Blackfin Credit Facilities were used to reimburse $889 million to VGLNG for prior expenditures related to the development and construction of the Blackfin Pipeline, and pay certain costs incurred in connection with the project financing. The remaining proceeds will be used to fund a portion of the costs to develop, construct and manage the Blackfin Pipeline.

The Blackfin Credit Facilities can be voluntarily prepaid at any time without penalty.

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VGLNG Revolving Credit Facility

Below is a summary of committed credit facilities outstanding for the VGLNG Revolving Credit Facility as of December 31, 2025:


	VGLNG Revolving Credit Facility(a)

Total commitments	$	2,000

Less:
Outstanding balances	—


Available commitments	$	2,000

Priority ranking	Senior secured
Interest rate on outstanding balances(b)	SOFR + 2.500%
	or
	base rate + 1.500%
Commitment fees on undrawn balance(b)	0.350%

____________

(a)Borrowings under the VGLNG Revolving Credit Facility are secured by a first-priority perfected security interest in, subject to certain exceptions, substantially all of the existing and future assets of VGLNG and any future guarantors, if any. As of the signing date, there are no guarantors. If certain of VGLNG’s subsidiaries incur or guarantee certain amounts of indebtedness in the future, then they will be required to guarantee the VGLNG Revolving Credit Facility.

(b)The rates are subject to reductions by up to 1.000% per annum based on achieving certain ratings requirements.

On November 7, 2025, VGLNG entered into a $2.0 billion senior secured credit facility (the "VGLNG Revolving Credit Facility"). Proceeds from the VGLNG Revolving Credit Facility are available to be used for general corporate purposes of VGLNG and its subsidiaries. The VGLNG Revolving Credit Facility and all borrowings thereunder will mature on November 7, 2030. In connection with the issuance of the VGLNG Revolving Credit Facility, VGLNG incurred debt issuance cost of $53 million primarily related to lender fees which will be amortized over the term of the credit facility.

VGLNG has the option to increase the commitments or establish one or more incremental term facilities under the Credit Agreement in an amount that, together with all loans and unfunded commitments outstanding under the Credit Agreement, shall not exceed 7.500% of the consolidated total assets of VGLNG and its restricted subsidiaries.

The VGLNG Revolving Credit Facility can be voluntarily prepaid at any time without premium or penalty.

Debt covenants

The Company's debt instruments contain certain customary affirmative and negative covenants that among other things, limit the Company's ability to incur additional indebtedness, create liens, dispose of assets, or pay dividends, distributions or other restricted payments. The Company's credit facilities include financial covenants that requires the borrower to maintain a specified historical debt service coverage ratio, as of a specified date in the respective agreement. As of December 31, 2025, each of the Company's issuers was in compliance with all covenants related to their respective debt obligations.

The Calcasieu Project, Plaquemines Project, the CP2 Project and Blackfin are restricted from making certain distributions to Venture Global under the agreements governing their respective indebtedness. These restrictions are in place until, among other requirements, the projects have established the appropriate operating reserves and historical and projected debt service reserves. The restricted net assets of the Company's consolidated subsidiaries was approximately $16.5 billion as of December 31, 2025.

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Interest expense on debt

The following table presents the total interest expense incurred on debt and other instruments:


	Years ended December 31,
		2025		2024		2023

Stated interest		$	2,263	$	1,890	$	1,038
Amortization of debt discounts, premiums and issuance costs		175		141		138
Other interest and fees		97		69		114
Total interest cost		2,535		2,100		1,290
Capitalized interest		(1,081)		(1,516)		(649)
Total interest expense, net		$	1,454	$	584	$	641

Note 12 – Derivatives

Overview of derivative instruments

Interest rate swaps

The Company has entered into interest rate swaps to mitigate its exposure to variability in interest payments associated with certain variable rate debt. None of the Company's interest rate swaps was designated as cash flow hedges as of December 31, 2025 or December 31, 2024.

During the year ended December 31, 2025, the Company settled a pro rata portion of the interest rate swaps associated with the Plaquemines Credit Facilities and received $1.1 billion of cash proceeds. See Note 11 – Debt for further discussion.

The following table summarizes outstanding interest rate swaps, all of which receive variable rate compounding SOFR:


						Outstanding notional as of
						December 31,
Debt instrument	Latest maturity	Mandatory early termination	Pay fixed rate(a)	Maximum notional		2025		2024

CP2 Credit Facilities	2049	2032	4.04%	$	9,527	$	1,402	$	—
Plaquemines Credit Facilities	2047	2029	2.46%	2,051		2,051		8,089
Blackfin Credit Facilities	2047	2030 & 2032	3.71%	1,191		1,191		—
Calcasieu Pass Credit Facilities	2036	2026	2.56%	783		783		969
Total notional				$	13,552	$	5,427	$	9,058

____________

(a)Represents a weighted-average fixed rate based on the maximum notional.

Natural gas supply contracts

The Company has entered into natural gas supply contracts for the supply of feed gas to its projects. Natural gas supply contracts which have not been designated or qualifying as NPNS are recognized as either derivative assets or liabilities and measured at fair value. None of the Company's natural gas supply contracts was designated as NPNS as of December 31, 2025. None of the Company's natural gas supply contracts was designated as hedges as of December 31, 2025 or December 31, 2024.

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The following table summarizes outstanding natural gas supply contracts recognized as derivatives (notional amount in millions of MMBtus):


		Total notional as of
		December 31,
	Latest maturity	2025	2024

Natural gas supply contracts	2039	3,613	2,048

Overview of results

The following table summarizes the fair value and classification of derivatives on the consolidated balance sheets:


		December 31,
	Balance sheet location	2025		2024

Assets
Interest rate swaps	Derivative assets	$	36	$	150
Natural gas supply contracts	Derivative assets	29		4
Interest rate swaps	Noncurrent derivative assets	203		1,459
Natural gas supply contracts	Noncurrent derivative assets	13		23
Total assets		$	281	$	1,636

Liabilities
Interest rate swaps	Accrued and other liabilities	$	32	$	1
Natural gas supply contracts	Accrued and other liabilities	72		12
Interest rate swaps	Other noncurrent liabilities	63		2
Natural gas supply contracts	Other noncurrent liabilities	89		12
Total liabilities		$	256	$	27

The following table presents the gross and net fair value of outstanding derivatives:


	December 31,
	2025						2024
	Gross balance		Balance subject to netting		Net balance		Gross balance		Balance subject to netting		Net balance

Derivative assets	$	296	$	(15)	$	281	$	1,648	$	(12)	$	1,636
Derivative liabilities	(271)		15		(256)		(39)		12		(27)

The following table presents the pre-tax effects of derivative instruments recognized in earnings:


		Years ended December 31,
	Line item		2025		2024		2023

Natural gas supply contracts	Cost of sales		$	120	$	(3)	$	—
Natural gas supply contracts	Development expense		2		—		—
Interest rate swaps	Gain (loss) on interest rate swaps		(220)		774		174

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Credit-risk related contingent features

Interest rate swaps

The interest rate swap agreements contain cross default provisions whereby if the Company were to default on certain indebtedness, it could also be declared in default on its derivative obligations and may be required to net settle the outstanding derivative liability positions with its counterparties. As of December 31, 2025, the Company had not posted any collateral related to these agreements and was not in breach of any agreement provisions. The aggregate fair value of the Company's interest rate swap derivative instruments with credit-risk related contingent features in a net liability position was $95 million as of December 31, 2025.

Natural gas supply contracts

Certain natural gas supply contracts contain credit risk-related contingent features which stipulate that if the Company's credit ratings were to change, it could be required to provide additional collateral. As of December 31, 2025, the Company would not be required to post any collateral related to these contracts if the credit-risk related contingent features were triggered, as the delivery of the underlying commodity had not yet commenced. The aggregate fair value of the Company's natural gas supply contracts with credit-risk related contingent features in a net liability position was $55 million as of December 31, 2025.

Note 13 – Fair Value Measurements

The following table presents financial assets and liabilities measured at fair value on a recurring basis and indicates their levels within the fair value hierarchy:


	December 31,
	2025								2024
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Money market funds(a)	$	340	$	—	$	—	$	340	$	1,373	$	—	$	—	$	1,373
Interest rate swaps(b)	—		245		—		245		—		1,609		—		1,609
Natural gas supply contracts(b)	—		1		50		51		—		—		39		39
Total	$	340	$	246	$	50	$	636	$	1,373	$	1,609	$	39	$	3,021

Liabilities
Interest rate swaps(c)	$	—	$	102	$	—	$	102	$	—	$	3	$	—	$	3
Natural gas supply contracts(c)	—		20		149		169		—		3		33		36
Total	$	—	$	122	$	149	$	271	$	—	$	6	$	33	$	39

____________

(a)Included in cash and cash equivalents on the consolidated balance sheets.

(b)Included in derivative assets and noncurrent derivative assets on the consolidated balance sheets.

(c)Included in accrued and other liabilities and other noncurrent liabilities on the consolidated balance sheets.

Interest rate swaps

The fair values of the Company's interest rate swaps are classified as Level 2 and determined using a discounted cash flow method that incorporates observable inputs. The fair value calculation includes a credit valuation adjustment and forward interest rate curves for the same periods of the future maturity dates of the interest rate swaps. For further discussion, see Note 12 – Derivatives.

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Level 3 unobservable inputs

The Company determines the fair value of its natural gas supply contracts using either an income or options-based approach. This incorporates present value techniques using a risk free rate of return, observable forward commodity price curves, and may incorporate other significant unobservable inputs. Significant unobservable inputs include implied forward curves at illiquid delivery locations and, if an option pricing model is used, volatility assumptions derived from observed historical market data adjusted for evolving industry conditions and market trends as of the balance sheet date as well as counterparty credit risk adjustments.

Due to the uncertainty surrounding these inputs, certain natural gas supply contracts are classified as Level 3 in the fair value hierarchy. Changes in these inputs can have a significant impact on the valuation of the Company's natural gas supply contracts, which can result in a significantly higher or lower estimated fair value. See Note 12 – Derivatives for further discussion.

The following table includes quantitative information for the unobservable inputs for Level 3 natural gas supply contracts as of December 31, 2025 (natural gas price amounts in dollars):

Valuation approach

Significant unobservable input

Range of significant unobservable input

Arithmetic average of significant unobservable input

Discounted cash flow

Forward natural gas price per MMBtu(a)

$2.63 to $5.34

3.72

Option pricing model

Volatility

13.5% to 68.6%

24.7

____________

(a) At illiquid delivery locations.

The following table sets forth a reconciliation of changes in the net fair value of derivative instruments measured at fair value on a recurring basis using Level 3 inputs:


	Years ended December 31,
	2025		2024

Beginning balance as of January 1	$	6	$	—
Total realized and unrealized loss included in earnings	(172)		(9)
Settlements	63		15
Transfer out of Level 3	4		—
Ending balance as of December 31	$	(99)	$	6

Unrealized gain (loss) included in earnings	$	(109)	$	6

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Other financial instruments

The following table presents the carrying value, fair value and fair value hierarchy of outstanding debt instruments in the consolidated balance sheets:


	December 31, 2025
	Carrying value		Fair value
			Level 1		Level 2		Level 3		Total

Fixed rate debt	$	25,334	$	25,426	$	84	$	—	$	25,510
Variable rate debt	9,478		1,078		8,403		—		9,481


	December 31, 2024
	Carrying value		Fair value
			Level 1		Level 2				Level 3		Total

Fixed rate debt	$	15,834	$	16,085	$	84	$	—	$	—	$	16,169
Variable rate debt	13,717		—		13,717		0		—		13,717

Note 14 – Income Taxes

The Company is a taxpayer in multiple jurisdictions within the U.S. The Company is also a taxpayer in certain international jurisdictions due to its operations outside the U.S.

The Company's United States and foreign income before income tax expense were as follows:


	Years ended December 31,
	2025		2024		2023
United States	$	3,347	$	2,181	$	4,432
Foreign	16		2		—
Total income before income tax expense	$	3,363	$	2,183	$	4,432

Income tax expense consisted of the following:


	Years ended December 31,
	2025		2024		2023

Current
Federal	$	(7)	$	(14)	$	133
State	(3)		4		6
Total current income tax expense (benefit)	(10)		(10)		139

Deferred
Federal	656		439		681
State	(11)		8		(4)
Foreign	(5)		—		—
Total deferred income tax expense	640		447		677
Total income tax expense	$	630	$	437	$	816

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The following is a reconciliation of the statutory federal income tax rate to the effective tax rate:


	Years ended December 31,
	2025				2024				2023
	Amount		Percent		Amount		Percent		Amount		Percent

US Federal statutory tax	$	706	21.0	%	$	459	21.0	%	$	931	21.0	%
State and local income taxes, net of federal income tax effect(a)	(14)		(0.4)	%	10		0.4	%	2		—	%
Foreign tax effects
Other foreign jurisdictions	(7)		(0.2)	%	—		—	%	1		—	%
Effect of cross-border tax laws
Foreign derived intangible income	—		—	%	—		—	%	(80)		(1.8)	%
Other	5		0.1	%	—		—	%	—		—	%
Tax credits
Research and development tax credits	(12)		(0.4)	%	(27)		(1.2)	%	—		—	%
Changes in valuation allowance	5		0.2	%	—		—	%	2		—	%
Nontaxable or nondeductible items
Stock options	(82)		(2.4)	%	(6)		(0.3)	%	(28)		(0.6)	%
Other	24		0.7	%	(8)		(0.3)	%	(12)		(0.2)	%
Changes in unrecognized tax benefits	5		0.1	%	9		0.4	%	—		—	%
Effective tax rate	$	630	18.7	%	$	437	20.0	%	$	816	18.4	%

____________

(a) State taxes in Louisiana made up the majority (greater than 50 percent) of the tax effect in this category.

Income taxes paid (net of refunds) consisted of the following:


	Years ended December 31,
	2025		2024		2023

U.S. Federal	$	(11)	$	—	$	126
U.S. State and local
Louisiana	—		10		1
Total U.S. State and local	—		10		1

Foreign taxes:
Other	—		1		1
Total foreign taxes	—		1		1
Total income taxes paid (net of refunds)	$	(11)	$	11	$	128

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Significant components of deferred tax assets and liabilities are included in the table below:


	December 31,
	2025		2024

Deferred tax liabilities
Derivative assets	$	(14)	$	(344)
Outside basis in Calcasieu Holdings	(1,127)		(1,195)
Property, plant and equipment	(3,375)		(1,763)
Right-of-use assets	(220)		(194)
Other deferred tax liabilities	(5)		(8)
Total deferred tax liabilities	$	(4,741)	$	(3,504)

Deferred tax assets
Lease liabilities	$	227	$	199
Net operating loss and other carryforwards	2,275		1,636
Stock-based compensation	40		34
Accrued expenses	55		45
Asset retirement obligations	30		80
Other deferred tax assets	8		6
Total deferred tax assets	$	2,635	$	2,000

Less: Valuation allowance	(207)		(133)
Net deferred tax liabilities	$	(2,313)	$	(1,637)

As of December 31, 2025, the Company had accumulated federal and foreign net operating loss carryforwards of $10.0 billion and $25 million, respectively, with an indefinite carryforward period. As of December 31, 2025, the Company also had accumulated state net operating loss carryforwards of approximately $3.4 billion, of which $42 million will expire by 2037. Utilization of these net operating losses may be limited when there is an ownership change as defined by Section 382 of the Internal Revenue Code. As of December 31, 2025, the Company did not believe any of its net operating losses were limited under these rules. As of December 31, 2025, the Company had accumulated tax credit carryforwards of $6 million, all of which will expire by 2045.

Net operating losses may also be limited when there is a separate return limitation year (“SRLY”). These rules generally limit the use of net operating loss carryforwards to the amount of taxable income that the net operating loss-producing entity contributes to the consolidated group's taxable income. Net operating losses subject to the SRLY rules may also be subject to Section 382 limitations. Of the $10.0 billion federal net operating loss carryforward as of December 31, 2025, $23 million is currently subject to the SRLY rules.

The Company maintains a valuation allowance against its federal deferred tax assets related to its SRLY tax attributes and its state deferred tax assets for which it continues to believe the more-likely-than-not recognition threshold has not been met. The Company's valuation allowances increased by $74 million during the year ended December 31, 2025 to $207 million as of December 31, 2025. This increase was primarily due to state valuation allowance activity.

The Company had $13 million and $9 million of unrecognized tax benefits as of December 31, 2025 and 2024 respectively, all of which would favorably affect the effective income tax rate, if recognized. For the years ended December 31, 2025 and 2024, the Company's accrued interest and penalties related to unrecognized tax benefits were not material. It is possible that the ultimate outcome of future examinations may exceed the Company's provision for current unrecognized tax benefits.

The Company remains subject to examination of its U.S. federal and state income tax returns for the tax years ended 2021 through 2025. Tax authorities may have the ability to review and adjust carryover tax attributes that were generated prior to these periods. As of December 31, 2025, VGLNG and Calcasieu Pass Holdings, LLC

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("Calcasieu Holdings"), subsidiaries of the Company, were under exam by the Internal Revenue Service for the 2022 tax year.

The Organization for Economic Co-operation and Development has issued “Pillar Two” model rules introducing a global minimum tax of 15% on a country-by-country basis, with certain aspects intended to be effective on January 1, 2025. Since the Company generally does not have material operations in jurisdictions with tax rates lower than the proposed Pillar Two minimum, any legislation enacted consistent with the Pillar Two model rules is not expected to have a material effect on the Company's financial statements.

In July 2025, the One Big Beautiful Bill Act ("the Act") was signed into law in the U.S. The Act contains several provisions related to corporate income taxes, including the extension of many expiring provisions from the Tax Cuts and Jobs Act of 2017 and modifications to the international tax framework. The changes introduced by the Act did not have a material impact on the Company’s annual effective tax rate for 2025.

Note 15 – Commitments and Contingencies

Commitments

The following is a schedule of the Company's future minimum commitments as of December 31, 2025:


Years ended December 31,	Natural gas supply		Firm transportation		Regasification capacity		Other		Total

2026	$	3,371	$	430	$	30	$	69	$	3,900
2027	3,188		680		30		56		3,954
2028	2,085		840		30		21		2,976
2029	1,199		950		42		16		2,207
2030	437		940		70		13		1,460
Thereafter	335		12,283		688		43		13,349
Total	$	10,615	$	16,123	$	890	$	218	$	27,846

Natural gas supply

The Company has entered into natural gas forward purchase contracts for the supply of feed gas to its LNG projects. The Company intends to take physical delivery of the contracted quantities through March 2032 at a purchase price indexed to the Henry Hub price for natural gas.

Firm transportation agreements

The Company has entered into long-term natural gas firm transportation service agreements with various pipeline companies to secure the natural gas transportation requirements for its LNG projects through April 2050.

Credit arrangements

The Company has entered into certain credit arrangements to secure the transportation of natural gas. As of December 31, 2025, the maximum undiscounted potential exposure associated with these arrangements was $260 million. This amount is not currently recognized as a liability on our consolidated balance sheet. To date, no amounts have been drawn against these arrangements.

Litigation

The Company is involved in certain claims, suits, and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount

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of loss can be reasonably estimated. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that the Company will have the liquidity to pay such claims as they arise.

Where no accrued liability has been recognized, it may be reasonably possible that some matters could be decided unfavorably to the Company. This could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of December 31, 2025.

Disputes with certain customers under the Calcasieu Project's post-COD SPAs are accounted for under ASC 606, Revenue from Contracts with Customers. See Note 4 – Revenue from Contracts with Customers for discussion of certain disputes with customers.

Note 16 – Equity

IPO and related transactions

On January 27, 2025, the Company completed its IPO in which it issued and sold 70 million shares of Class A common stock, par value $0.01, at a public offering price of $25.00 per share. The Company received proceeds of $1.7 billion, net of underwriting discounts and commissions of $70 million and offering expenses of $10 million. Prior to the completion of the IPO, all shares of Class A common stock held by VG Partners, approximately 1.97 billion shares, were converted into an equal number of shares of Class B common stock.

Preferred and common stock

The Company's Class A common stock has one vote per share and its Class B common stock has ten votes per share. The par value of the Class A common stock and the Class B common stock is $0.01 per share.

As of December 31, 2024, the Company had 1 million shares of preferred stock, 4.5 billion shares of Class A common stock and 1 million shares of Class B common stock authorized for issuance. In connection with the Company's IPO in January 2025, the Company amended and restated its certificate of incorporation and revised the number of shares authorized for issuance. As of December 31, 2025, the Company had 200 million shares of preferred stock, 4.4 billion shares of Class A common stock and 3.0 billion shares of Class B common stock authorized for issuance.

Dividends

During the year ended December 31, 2025, the Company's board of directors declared dividends of $0.03 per share to holders of its outstanding common stock, which were paid during the year ended December 31, 2025 in the aggregate amount of $83 million.

During the year ended December 31, 2024, the Company's board of directors declared the payment of cash dividends to holders of the Company's outstanding common stock in an aggregate amount of $160 million that were paid on a pro rata basis in four equal installments of $40 million over four consecutive calendar quarters on the last business day of each such calendar quarter, commencing on September 30, 2024.

Reorganization Transactions

During the year ended December 31, 2023, prior to the Reorganization Transactions, VGLNG repurchased 5,000 shares of its Series B common stock and 81,896 shares of its Series C common stock for $1.6 billion. This was recognized as a $1.2 billion and $0.4 billion reduction to stockholders' equity and noncontrolling interests, respectively.

In September 2023, in connection with the Reorganization Transactions, Venture Global completed the 2023 Merger whereby Legacy VG Partners merged with and into Venture Global, with VG Partners receiving 2.0 billion shares of Venture Global's Class A common stock in exchange for its equity interests in Legacy VG Partners.

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In addition, as part of the Reorganization Transactions, the VGLNG non-controlling shareholders holding 84,272 shares of VGLNG's Series C common stock received 381 million shares of Venture Global's Class A common stock, in a 4,520.3317-for-one exchange.

Upon completion of the Reorganization Transactions in September 2023, all shares of VGLNG's Series A, Series B and Series C common stock were owned and subsequently retired by the Company, resulting in a $2.0 billion reduction to retained earnings.

Note 17 – Redeemable Stock of Subsidiary

In August 2019, the Company issued 9 million redeemable preferred units ("CP Funding Redeemable Preferred Units") with an initial face value of $100 per preferred unit. The CP Funding Redeemable Preferred Units are redeemable at the Company's option or, following the eighth anniversary of the date of issuance, to the extent the Company has available cash as defined within Calcasieu Funding's ownership agreement. The CP Funding Redeemable Preferred Units are not convertible to common units or any other classes of interests and have no voting rights, except with respect to certain matters that require approval from the holders of the CP Funding Redeemable Preferred Units.

The CP Funding Redeemable Preferred Units pay cumulative, quarterly distributions at an initial rate of 10.0% per annum. Distributions can be paid in cash or in-kind by increasing the face value of the CP Funding Redeemable Preferred Units. Distributions paid in-kind following COD for the Calcasieu Project are subject to an additional 1.0% distribution. The distribution rate increases by 0.5% upon the eighth anniversary of the date of issuance and every six months thereafter up to a maximum rate of 15.0% per annum. As of December 31, 2025, all distributions have been paid in-kind.

The CP Funding Redeemable Preferred Units have an aggregate liquidation preference of $900 million plus accrued or paid-in-kind distributions. The Calcasieu Project declared COD on April 15, 2025. Following COD of the Calcasieu Project through August 19, 2027, no distributions of available cash are permitted from Calcasieu Funding to Venture Global or its affiliates until all accrued distributions on the CP Funding Redeemable Preferred Units have been fully settled in cash. As of December 31, 2025, the accrued distribution balance on the CP Funding Redeemable Preferred Units was $796 million. Further, on and after August 19, 2027, no distributions of available cash—beyond what is deemed necessary by management to fund VGCP's operating costs, including debt service requirements—will be permitted from Calcasieu Funding to Venture Global or its affiliates until the CP Funding Redeemable Preferred Units have been fully redeemed in cash. As of December 31, 2025, the CP Funding Redeemable Preferred Units full redemption value was $1.7 billion.

The following table summarizes the change in redeemable stock of subsidiary on the consolidated balance sheets:


	Years ended December 31,
	2025		2024		2023

Beginning balance as of January 1	$	1,529	$	1,385	$	1,255
Paid-in-kind distributions(a)	167		144		130
Ending balance as of December 31	$	1,696	$	1,529	$	1,385

____________

(a)Presented as net income attributable to redeemable stock of subsidiary on the consolidated statements of operations.

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Note 18 – Non-Controlling Interests

VGLNG Series A Preferred Shares

In September 2024, VGLNG, a direct controlled subsidiary of the Company, issued 3 million Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock (the "VGLNG Series A Preferred Shares") which represent third-party ownership in the net assets of VGLNG and have a cumulative net balance of $2.9 billion. The annual dividend rate on the VGLNG Series A Preferred Shares is currently 9.000%. Cumulative cash dividends on the VGLNG Series A Preferred Shares are payable semiannually, in arrears, when, and if, declared by the VGLNG board of directors.

The VGLNG Series A Preferred Shares are not convertible or exchangeable for any other securities or property and have no voting rights, aside from those required by law. The VGLNG Series A Preferred Shares are perpetual and have no maturity date. The VGLNG Series A Preferred Shares may only be redeemed at the option of the Company, in whole or in part, on one or more occasions at any time after September 30, 2029 (the "First Reset Date") and in certain other circumstances prior to the First Reset Date. The VGLNG Series A Preferred Shares have a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends.

During the year ended December 31, 2025, the Company accumulated, declared, and paid $270 million, or $90.00 per share, of dividends on the VGLNG Series A Preferred Shares. The balance of accumulated but undeclared dividends was $68 million, or $22.75 per share, as of December 31, 2025 and 2024.

Calcasieu Holdings

In August 2019, Calcasieu Holdings, an indirect controlled subsidiary of the Company, issued 4 million convertible preferred units (the "CP Holdings Convertible Preferred Units") with an initial face value of $100 per preferred unit, which represent third-party ownership in the net assets of Calcasieu Holdings.

Upon COD of the Calcasieu Project in April 2025, the CP Holdings Convertible Preferred Units converted into Class B common units of Calcasieu Holdings. This conversion was equal to approximately 23% of the total outstanding common units of Calcasieu Holdings, reducing the Company's common equity interest in the Calcasieu Project to approximately 77%.

Prior to COD, the CP Holdings Convertible Preferred Units paid a cumulative quarterly distribution recognized as net income attributable to non-controlling interests. Subsequent to COD, the Class B common units of Calcasieu Holdings are adjusted by the amount of earnings or other comprehensive income (loss) attributable to the Class B common unit ownership.

The following table summarizes the changes in the third-party ownership in the net assets of Calcasieu Holdings:











	Years ended December 31,
	2025		2024		2023

Beginning balance as of January 1	$	575	$	575	$	547
Net income attributable to non-controlling interests	36		59		57
Distributions	(18)		(59)		(29)
Ending balance as of December 31	$	593	$	575	$	575

Note 19 – Stock-Based Compensation

In connection with the Reorganization Transactions, on September 25, 2023, the Company adopted the 2023 Stock Option Plan, as amended (the "2023 Plan"), which replaced the 2014 Stock Option Plan (the "Predecessor Plan"). Upon the adoption of the 2023 Plan, all options previously granted and then outstanding under the

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Predecessor Plan (representing options to purchase 86,664 shares of VGLNG's Series A common stock) were automatically converted, on a 4,520.3317-for-one basis in accordance with and pursuant to the terms of the Predecessor Plan, into options to purchase shares of the Company's Class A common stock subject to the terms and conditions of the 2023 Plan. There were no other material differences between the terms and conditions of the 2023 Plan and the Predecessor Plan. Upon its adoption, the 2023 Plan provided for the issuance of approximately 429 million shares of the Company's Class A common stock. As noted below, no further awards may be granted under the 2023 Plan.

In connection with the Company's IPO in January 2025, the Company adopted the Venture Global, Inc. 2025 Omnibus Incentive Plan (the "Omnibus Incentive Plan"), under which its employees may receive equity incentive compensation, including stock options, restricted stock units and other awards in the future. As of the effectiveness of the Omnibus Incentive Plan in January 2025, all shares that remained available for issuance under the 2023 Plan became available for issuance under the Omnibus Incentive Plan and no further equity awards will be granted under the 2023 Plan. Awards that remained outstanding under the 2023 Plan upon the adoption of the Omnibus Incentive Plan remain outstanding under, and subject to the terms and conditions of, the 2023 Plan. The total number of shares of Class A common stock authorized for issuance under the Omnibus Incentive Plan is approximately 172 million shares, and is subject to annual automatic evergreen increases thereafter.

Stock option activity

A summary of stock-based compensation activity for the year ended December 31, 2025 is presented below (share information in millions):


	Options	Weighted average exercise price per share		Weighted average remaining contractual life (in years)	Aggregate intrinsic value

Outstanding at December 31, 2024	286	$	1.43
Granted	14	$	24.28
Exercised	(37)	$	0.96		$	390
Forfeited or expired	(37)	$	0.72
Outstanding at December 31, 2025	226	$	3.07	4.40	$	1,094
Exercisable at December 31, 2025	208	$	1.87	4	$	1,074

The Black-Scholes fair value of the stock options granted during the years ended December 31, 2025, 2024 and 2023 was determined using the following assumptions:

Years ended December 31,

2025

2024

2023

Weighted average

Range

Weighted average

Range

Weighted average

Range

Expected life(a)

6.1 years

6.1 to 6.3 years

6.1 years

Risk-free interest rate(b)

4.4%

3.9% to 4.5%

4.2%

4.1%

3.6% to 4.6%

Expected volatility(c)

39.2%

39.1% to 40.1%

40.4%

40.2%

40.1% to 40.4%

Expected dividend yield

—%

—% to —%

—%

—% to —%

—%

—% to —%

____________

(a)Computed using the simplified method based on the mid-point between the vesting and contractual terms since the Company did not have sufficient historical information to estimate the expected life.

(b)The risk-free rate is based on U.S. Treasury bonds issued with similar maturity dates to the expected life of the grant.

(c)Expected volatility is based on a weighted measure of historical, implied and expected volatility of comparable companies in the Company's industry sector.

The options granted during the years ended December 31, 2025, 2024 and 2023, were granted at exercise prices equal to the fair market value of VGLNG's Series A common stock or Venture Global's Class A common

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stock, as applicable, on the respective grant dates. The options have a 10-year term and generally vest in equal quarterly installments over a four-year service period, subject to continued service through each vesting date. Upon exercise, the Company issues new shares of Class A common stock. The weighted average grant-date fair value of options granted during the years ended December 31, 2025, 2024 and 2023 were $11.07, $2.98, and $1.90, respectively.

The total stock-based compensation costs recognized is as follows:


	Years ended December 31,
	2025		2024		2023

Total stock-based compensation costs	$	54	$	22	$	28
Capitalized to property, plant and equipment	(8)		—		—
Stock based compensation expense, before tax	$	46	$	22	$	28

Income tax benefit recognized related to stock-based compensation	$	84	$	6	$	32

As of December 31, 2025, there remained $129 million of total unrecognized compensation cost related to non-vested stock-based compensation grants. The Company expects this expense to be recognized over a weighted-average period of approximately three years.

During the year ended December 31, 2025, the Company received $35 million from the exercise of options and recognized a net income tax benefit of $74 million. There were no options exercised during the years ended December 31, 2024 and 2023.

During the years ended December 31, 2025, 2024 and 2023, the Company paid $32 million, $29 million, and $152 million, respectively, to settle a subset of fully vested options. The cash settlement did not constitute a modification of the awards or result in additional stock-based compensation expense.

Note 20 – Earnings per Share

Earnings per share is calculated using the two-class method and presented on a combined basis since the Class A common stock and the Class B common stock have identical rights and privileges, except for voting rights. There was no Class B common stock outstanding during the years ended December 31, 2024 and 2023. The number of weighted average shares outstanding prior to the 2023 Merger were calculated based on the one-for-one exchange ratio of 2.0 billion shares of the Company's Class A common stock issued to VG Partners in exchange for 100% of the Legacy VG Partners members' equity interests in connection with the 2023 Merger.

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The following table sets forth the computation of net income per share attributable to the Class A and the Class B common stock outstanding (share amounts in millions):


	Years ended December 31,
		2025		2024		2023

Net income		$	2,733	$	1,746	$	3,616
Less: Net income attributable to redeemable stock of subsidiary		167		144		130
Less: Net income attributable to non-controlling interests		36		59		805
Less: Dividends on VGLNG Series A preferred shares		270		68		—
Net income attributable to common stockholders		$	2,260	$	1,475	$	2,681

Weighted average shares of common stock outstanding
Basic		2,426		2,350		2,070
Dilutive stock options outstanding		209		235		73
Diluted		2,635		2,585		2,143
Net income attributable to common stockholders per share—basic(a)		$	0.93	$	0.63	$	1.30
Net income attributable to common stockholders per share—diluted(a)		$	0.86	$	0.57	$	1.25

Anti-dilutive stock options excluded from diluted net income per share		14		—		—

____________

(a) Earnings per share may not recalculate exactly due to rounding.

Note 21 – Related Parties

The Company has a management services agreement with VG Partners. During the years ended December 31, 2025, 2024 and 2023, the Company incurred $12 million, $7 million and $2 million, respectively, in connection with this agreement, which was recognized as general and administrative expense on the consolidated statements of operations.

Note 22 – Supplemental Cash Flow Information

The following table sets forth supplemental disclosure of cash flow information:


	Years ended December 31,
	2025		2024		2023

Accrued capital expenditures	$	1,579	$	2,091	$	1,248
Cash paid for interest, net of amounts capitalized	1,000		338		368
Conversion of equity method investment to property, plant and equipment	327		319		—
Accrued dividends and distributions	—		95		15



Right-of-use assets in exchange for new finance lease liabilities	7		178		10
Right-of-use assets in exchange for new operating lease liabilities	227		294		90

Cash paid for operating leases	141		81		45

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Note 23 – Segment Information

The Company has multiple operating segments, including the Company's LNG projects, its sales and shipping business, and its pipeline activities. Each LNG project operating segment includes activity of both the respective liquefaction facility and export terminal and the associated pipeline(s) that will supply the natural gas to that facility. The Company's chief operating decision maker ("CODM") is the Company's Chief Executive Officer. The CODM allocates resources, assesses performance and manages the business according to these operating segments. The Company's performance is evaluated based on income (loss) from operations of the respective segment.

The Company has four reportable segments. Operating segments that are not quantitatively material for reporting purposes have been combined with corporate activities as corporate, other and eliminations. Activities reported in corporate, other and eliminations include immaterial operating segments, costs which are overhead in nature and not directly associated with the operating segments, including certain general and administrative and marketing expenses, and inter-segment eliminations. Prior period presentations have been reclassified to conform to the current segment reporting structure to separately disclose our sales and shipping business that is now quantitatively material.

The following tables present financial information by segment, including significant segment expenses regularly provided to the CODM, and a reconciliation of segment income (loss) from operations to income (loss) before income tax expense on the consolidated statements of operations for the periods indicated.


	Year ended December 31, 2025
	Calcasieu Project		Plaquemines Project		CP2 Project		Sales and Shipping		Corporate, other and eliminations		Total

Revenue	$	4,125	$	9,175	$	1	$	2,518	$	(2,050)	$	13,769

Operating expense
Cost of sales	2,198		3,863		—		1,994		(2,135)		5,920
Operating and maintenance expense	375		359		29		228		(16)		975
General and administrative expense	15		63		47		6		302		433
Development expense	—		49		203		—		92		344
Depreciation and amortization	221		613		—		42		65		941
Total operating expense	2,809		4,947		279		2,270		(1,692)		8,613

Income (loss) from operations	$	1,316	$	4,228	$	(278)	$	248	$	(358)	$	5,156
Interest income											151
Interest expense, net											(1,454)
Loss on interest rate swaps											(220)
Loss on financing transactions											(267)
Loss on foreign currency transactions											(3)
Income before income tax expense											$	3,363

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	Year ended December 31, 2024
	Calcasieu Project		Plaquemines Project		CP2 Project		Sales and Shipping		Corporate, other and eliminations		Total

Revenue	$	4,916	$	23	$	2	$	329	$	(298)	$	4,972

Operating expense
Cost of sales	1,363		14		—		266		(292)		1,351
Operating and maintenance expense	452		94		—		53		(10)		589
General and administrative expense	15		62		16		17		202		312
Development expense	6		54		485		1		89		635
Depreciation and amortization	267		16		1		12		26		322
Total operating expense	2,103		240		502		349		15		3,209

Income (loss) from operations	$	2,813	$	(217)	$	(500)	$	(20)	$	(313)	$	1,763
Interest income											244
Interest expense, net											(584)
Gain on interest rate swaps											774
Loss on financing transactions											(14)
Income before income tax expense											$	2,183


	Year ended December 31, 2023
	Calcasieu Project		Plaquemines Project		CP2 Project		Sales and Shipping		Corporate, other and eliminations		Total

Revenue	$	7,897	$	—	$	—	$	—	$	—	$	7,897

Operating expense
Cost of sales	1,684		—		—		—		—		1,684
Operating and maintenance expense	319		80		—		—		(8)		391
General and administrative expense	15		57		—		6		146		224
Development expense	44		50		362		1		33		490
Depreciation and amortization	256		—		—		—		21		277
Insurance recoveries, net	(19)		—		—		—		—		(19)
Total operating expense	2,299		187		362		7		192		3,047

Income (loss) from operations	$	5,598	$	(187)	$	(362)	$	(7)	$	(192)	$	4,850
Interest income											172
Interest expense, net											(641)
Gain on interest rate swaps											174
Loss on financing transactions											(123)
Income before income tax expense											$	4,432

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The following table presents the capital expenditures and total assets by segment for the periods indicated:


	Capital expenditures(a)						Total assets
	Years ended December 31,						December 31,
	2025		2024		2023		2025		2024

Calcasieu Project	$	88	$	373	$	98	$	6,955	$	7,181
Plaquemines Project	5,555		9,458		6,351		26,256		24,627
CP2 Project	5,257		2,179		831		10,857		3,643
Sales and shipping	754		403		51		2,485		1,473
Corporate, other and eliminations	1,787		1,685		824		6,893		6,567
Total	$	13,441	$	14,098	$	8,155	$	53,446	$	43,491

____________

(a) Includes financed capital expenditures.

The Company attributes revenues from external customers by delivery location. The following tables present the geographic locations of revenue and long-lived assets for the periods indicated:


	Revenue
	Years ended December 31,
	2025		2024		2023

United States	$	11,375	$	4,673	$	7,897
Germany	772		179		—
France	682		81		—
Netherlands	456		—		—
United Kingdom	164		—		—
Other	320		39		—
Total	$	13,769	$	4,972	$	7,897


	Long-lived assets
	December 31,
	2025		2024

United States	$	45,437	$	34,077
Foreign(a)	1,151		598
Total	$	46,588	$	34,675

____________

(a) Primarily LNG tankers domiciled in Bermuda.

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The following table presents the Company's revenue from individual external customers that were 10% or greater than total revenue:


	Years ended December 31,
	2025(a)	2024(b)	2023(c)

Customer A	23%	32%	13%
Customer B	14%	25%	33%
Customer C	13%	*	*
Customer D	*	15%	11%
Customer E	*	*	17%

____________

(*)Less than 10%.

(a) Revenue recognized at the Calcasieu Project, Plaquemines Project, and Sales and shipping.

(b) Revenue recognized at the Calcasieu Project and Sales and shipping.

Note 24 – Recent Accounting Pronouncements

The following table provides a description of a recently issued accounting pronouncement that has not yet been adopted as of December 31, 2025. Accounting pronouncements not listed below were assessed and determined to not have a material impact to the consolidated financial statements.

Standard

Description

Effect on the Company's consolidated financial statements

ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40)

In November 2024, the FASB issued ASU 2024-03, which enhances income statement disclosures. This requires public business entities to provide a tabular disclosure of relevant expense captions disaggregated into categories such as purchases of inventory, employee compensation, depreciation, intangible asset amortization, and amounts that are already required to be disclosed under current GAAP, a qualitative description of the amounts remaining in the relevant expense captions that are not separately disaggregated and the total amount of selling expenses and, in annual periods, an entity's definition of selling expenses.

The standard is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The standard should be applied on a prospective basis, and retrospective application is permitted.

The Company is currently evaluating the impact on the financial statement disclosures.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) are designed to ensure that information required to be disclosed by us in reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the appropriate time periods, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussions regarding required disclosure.

In designing and evaluating our disclosure controls and procedures, management recognizes that any disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints, and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

We, under the supervision of and with participation of our management, including our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of our disclosure controls and procedures. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective as of December 31, 2025.

Management’s Annual Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Securities Exchange Act. The Company’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. The Company’s internal controls over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal control over financial reporting may vary over time.

Management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, using the criteria set forth in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2025, providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP.

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Attestation Report of the Registered Public Accounting Firm

This Form 10-K does not include an attestation report from the Company's independent registered public accounting firm regarding internal control over financial reporting due to a transition period permitted by SEC rules applicable to newly public companies.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the fiscal quarter ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Director and Officer Trading Plans

Other than as set forth below, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) have entered into a trading plan intended to satisfy the affirmative defense of Rule 10b5-1(c) during the three months ended December 31, 2025:

Name

Title

Date of adoption

Aggregate number of securities to be purchased or sold

Date of expiration

Keith Larson

General Counsel and Secretary

November 19, 2025

10,000,000

December 31, 2026

Jonathan Thayer

Chief Financial Officer

November 24, 2025

5,000,000

December 31, 2026

Sarah Blake

Chief Accounting Officer

December 4, 2025

1,200,000

December 31, 2026

In addition, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) have adopted, modified or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408 of Regulation S-K).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Insider Trading Policies and Procedures

We maintain insider trading policies and procedures governing the purchase, sale, and/or other dispositions of our company’s securities by directors, officers, and employees that we believe are reasonably designed to promote compliance with insider trading laws, rules, and regulations, as well as NYSE listing standards. In addition, it is our general policy to comply with all applicable laws and regulation in conducting our business, including insider trading laws. A copy of our insider trading policy is filed as Exhibit 19 to this Form 10-K.

Information concerning compliance with Section 16(a) of the Exchange Act will be contained in our 2026 Proxy Statement under the caption " Security Ownership of Certain Beneficial Owners and Management-Delinquent Section 16(a) Reports" and is incorporated herein by reference.

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Code of Business Conduct and Ethics

Our board of directors has adopted a code of business conduct and ethics that applies to all of our employees, officers and directors, including our Co-Chairmen, Chief Executive Officer, Chief Financial Officer and other executive and senior financial officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of NYSE. The full text of our code of business conduct and ethics is posted on the investor relations section of our website at www.ventureglobal.com. We intend to disclose future amendments to our code of business conduct and ethics, or any waivers of such code, on our website or in public filings.

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required in Item 10 of Part III of this Form 10-K is incorporated by reference from our definitive proxy statement, which will be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31, 2025.

ITEM 11. EXECUTIVE COMPENSATION

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required in Item 11 of Part III of this Form 10-K is incorporated by reference from our definitive proxy statement, which will be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31, 2025.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required in Item 12 of Part III of this Form 10-K is incorporated by reference from our definitive proxy statement, which will be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31, 2025.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required in Item 13 of Part III of this Form 10-K is incorporated by reference from our definitive proxy statement, which will be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31, 2025.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is Ernst & Young LLP.

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required in Item 14 of Part III of this Form 10-K is incorporated by reference from our definitive proxy statement, which will be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31, 2025.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this Form 10-K.

(1) Financial Statements:

See Item 8.—Financial Statements and Supplementary Data above.

(2) Financial Statement Schedules:

See Schedule I – Condensed Financial Information of Venture Global, Inc. in Item 15(c) below.

(3) Exhibits:

See the exhibits required to be filed or furnished pursuant to Item 601 of Regulation S-K are included in Item 15(b) below.

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(b) Exhibits


Exhibit Number						Description

3.1†						Second Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2025)

3.2†						Amended and Restated By-Laws (incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on January 27, 2025)

4.1†						Description of Registrant's Securities Registered pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.1 to the Registrant’s Annual Report on Form 10-K filed on March 6, 2025)

4.2†						Form of Class A Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.1†						Amended and Restated Shareholders’ Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2025)

10.2†						Guaranty Agreement, dated as of April 21, 2021, by KBR, Inc., for the benefit of Venture Global Plaquemines LNG, LLC, pursuant to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 21, 2021, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.3†						Guaranty Agreement, dated as of April 21, 2021, by Zachry Holdings, Inc., for the benefit of Venture Global Plaquemines LNG, LLC, pursuant to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 21, 2021, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.4†						Guaranty Agreement, dated as of January 10, 2023, by KBR Inc., for the benefit of Venture Global Plaquemines LNG, LLC pursuant to the Engineering, Procurement and Construction Agreement, dated as of January 10, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.18 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.5†						Guaranty Agreement, dated as of January 10, 2023, by Zachry Holdings, Inc., for the benefit of Venture Global Plaquemines LNG, LLC pursuant to the Engineering, Procurement and Construction Agreement, dated as of January 10, 2023, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.19 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.6†						Guaranty Agreement, dated as of June 8, 2023, by Worley Limited, for the benefit of Venture Global CP2 LNG, LLC, pursuant to the Engineering, Procurement and Construction Agreement, dated as of May 12, 2023, by and between Venture Global CP2 LNG, LLC and Worley Field Services, Inc. (incorporated by reference to Exhibit 10.23 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.7§†						Third Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7, 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

10.8§†						Change Order No. 7, dated as of June 10, 2025, to the Third Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7, 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

10.9§†						Amendment No. 1 , dated as of Aug ust 29, 2025, to Third Amended and Restated Engineering, Procurement and Construction Agreement, dated as of A pril 7 , 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.10§						Change Order No. 8, dated as of December 19, 2025, to the Third Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7, 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.11§†						Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7, 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

10.12§†						Change Order No. 1, dated as of June 2, 2025, to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7, 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

10.13§						Change Order No. 2, dated as of November 12 , 2025, to the Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7, 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.14§						Amendment No. 1 , dated as of November 12, 2025, to Amended and Restated Engineering, Procurement and Construction Agreement, dated as of April 7 , 2025, by and between Venture Global Plaquemines LNG, LLC and KZJV LLC

10.15§†						Amended and Restated Engineering, Procurement and Construction Agreement, dated as of June 13, 2025, by and between Venture Global CP2 LNG, LLC and Worley Field Services Inc. (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

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10.16§†						Fourth Amended and Restated Letter of Agreement, dated as of April 7, 2023, by and between Venture Global LNG, Inc. and Baker Hughes Energy Services LLC (incorporated by reference to Exhibit 10.32 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.17§						Amendment No. 1, dated as of December 5, 2025, to Fourth Amended and Restated Letter of Agreement, dated as of April 7, 2023, by and between Venture Global LNG, Inc. and Baker Hughes Energy Services LLC

10.18§						Amendment No. 2, dated as of December 18, 2025, to Fourth Amended and Restated Letter of Agreement, dated as of April 7, 2023, by and between Venture Global LNG, Inc. and Baker Hughes Energy Services LLC

10.19§†						Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.33 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.20†						Guaranty Agreement, dated as of February 26, 2021, by Baker Hughes Holdings LLC, for the benefit of Venture Global Plaquemines LNG, LLC pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of February 26, 2021, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.34 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.21§†						Change Order No. 2, dated as of February 25, 2022, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.35 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.22§†						Change Order No. 3, dated as of October 24, 2022, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.36 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.23§†						Change Order No. 4, dated as of April 7, 2023, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.37 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.24§†						Change Order No. 5, dated as of May 18, 2023, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.38 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.25§†						Change Order No. 6, dated as of December 29, 2023, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.39 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.26§						Change Order No. 7, dated as of August 7, 2024, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.27§†						Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.40 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.28†						Guaranty Agreement, dated as of August 5, 2022, by Baker Hughes Holdings LLC, for the benefit of Venture Global Plaquemines LNG, LLC, pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.41 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.29§†						Change Order No. 1, dated as of April 7, 2023, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.42 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.30§†						Change Order No. 2, dated as of May 24, 2023, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.43 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.31§†						Change Order No. 3, dated as of August 29, 2024, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.44 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

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10.32§†						Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.45 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.33§†						Change Order No. 1, dated as of August 8, 2024, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.46 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.34§†						Change Order No. 2, dated as of November 15, 2024, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.47 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.35§						Change Order No. 3, dated as of August 22, 2025, to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC

10.36†						Purchase Order Contract for the Sale of Liquefaction Train System, dated as of December 13, 2024 by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.48 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.37†						Guaranty Agreement, dated as of April 13, 2023, by Baker Hughes Holdings LLC, for the benefit of Venture Global CP2 LNG, LLC, pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of April 7, 2023, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.49 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.38†						Guaranty Agreement, dated as of December 13, 2024, by Baker Hughes Holdings LLC, for the benefit of Venture Global CP2 LNG, LLC pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of December 13, 2024, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.113 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025 )

10.39†						Guaranty Agreement, dated as of January 2, 2025, by Venture Global LNG, Inc., for the benefit of Baker Hughes Energy Services LLC, pursuant to the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of December 13, 2024, by and between Baker Hughes Energy Services LLC and Venture Global CP2 LNG, LLC (incorporated by reference to Exhibit 10.114 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.40§†						Change Order No. 8, dated as of March 13, 2025, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on May 13, 2025)

10.41§						Change Order No. 9, dated as of November 26, 2025, to the Amended and Restated Purchase Order Contract for the Sale of Liquefaction Train System, dated as of January 19, 2022, by and between Baker Hughes Energy Services LLC and Venture Global Plaquemines LNG, LLC

10.42§†						Change Order No. 4, dated as of August 15, 2025, under the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Venture Global Plaquemines LNG, LLC and Baker Hughes Energy Services LLC (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.43§						Change Order No. 5, dated as of November 26, 2025, under the Purchase Order Contract for the Sale of Liquefaction Train System, dated as of August 5, 2022, by and between Venture Global Plaquemines LNG, LLC and Baker Hughes Energy Services LLC

10.44§†						Amended and Restated Ground Lease Agreement, dated as of July 15, 2019, by and between Venture Global Calcasieu Pass, LLC and JADP Venture, LLC (incorporated by reference to Exhibit 10.51 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.45§†						First Amendment to Amended and Restated Ground Lease Agreement, dated as of December 12, 2023, by and between Venture Global Calcasieu Pass, LLC and JADP Venture, LLC (incorporated by reference to Exhibit 10.52 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.46§†						Amended and Restated Ground Lease Agreement, dated as of June 20, 2019, by and between Venture Global Calcasieu Pass, LLC and Henry Venture LLC (incorporated by reference to Exhibit 10.53 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.47§†						Ground Lease Agreement, dated as of July 19, 2021, by and between Venture Global Plaquemines LNG, LLC and the Plaquemines Port Harbor and Terminal District (incorporated by reference to Exhibit 10.54 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.48§†						Ground Lease Agreement, dated as of January 19, 2022, by and between Plaquemines Land Ventures, LLC, and the Plaquemines Port Harbor and Terminal District (incorporated by reference to Exhibit 10.55 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

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10.49§†						Amended and Restated Ground Lease Agreement, dated as of September 19, 2023, by and between Cameron Land Ventures, LLC and J.A. Davis Properties, LLC (incorporated by reference to Exhibit 10.56 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.50§†						Ground Lease Agreement, dated of October 12, 2023, by and between Venture Global CP2 LNG, LLC, and Wilma Davis Bride Family, LLC (incorporated by reference to Exhibit 10.57 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.51§†						Ground Lease Agreement, dated as of October 12, 2023, by and between Venture Global CP2 LNG, LLC, and Ardoin Henry, LLC (incorporated by reference to Exhibit 10.58 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.52§†						Ground Lease Agreement, dated as of October 12, 2023, by and between Venture Global CP2 LNG, LLC and Miller Estate Leasing Company, LLC (incorporated by reference to Exhibit 10.59 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.53§†						Ground Lease Agreement, dated as of October 12, 2023, by and between Venture Global CP2 LNG, LLC, and Charlotte Ann LaBove and Carlotta Ann Savoie (incorporated by reference to Exhibit 10.60 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.54§†						Ground Lease Agreement, dated as of October 24, 2023, by and between Venture Global CP2 LNG, LLC and Cameron Parish Port, Harbor and Terminal District (incorporated by reference to Exhibit 10.61 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.55§†						Ground Lease Agreement, dated as of March 11, 2019, by and between Venture Global Calcasieu Pass, LLC and Henry Venture, LLC (incorporated by reference to Exhibit 10.62 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.56§†						Ground Lease Agreement, dated as of December 12, 2023, by and between Venture Global CP2 LNG, LLC and JADP Venture, LLC (incorporated by reference to Exhibit 10.63 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.57§†						Limited Liability Company Agreement, dated as of August 19, 2019, among Calcasieu Pass Funding, LLC and the Members named therein (incorporated by reference to Exhibit 10.64 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.58†						Limited Liability Company Agreement, dated as of August 19, 2019, by and among Calcasieu Pass Holdings, LLC and the Members named therein (incorporated by reference to Exhibit 10.65 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.59†						Amendment No. 1 to the Limited Liability Company Agreement of Calcasieu Pass Funding, LLC, dated as of February 8, 2021 (incorporated by reference to Exhibit 10.66 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.60†						Amendment No. 1 to the Limited Liability Company Agreement of Calcasieu Pass Holdings, LLC, dated as of February 8, 2021 (incorporated by reference to Exhibit 10.67 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.61†						Amendment No. 2 to the Limited Liability Company Agreement of Calcasieu Pass Funding, LLC, dated as of October 27, 2021 (incorporated by reference to Exhibit 10.68 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.62†						Amendment No. 2 to the Limited Liability Company Agreement of Calcasieu Pass Holdings, LLC, dated as of October 27, 2021 (incorporated by reference to Exhibit 10.69 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.63†						Amendment No. 3 to the Limited Liability Company Agreement of Calcasieu Pass Funding, LLC, dated as of July 30, 2022 (incorporated by reference to Exhibit 10.70 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.64†						Amendment No. 3 to the Limited Liability Company Agreement of Calcasieu Pass Holdings, LLC, dated as of July 30, 2022 (incorporated by reference to Exhibit 10.71 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.65§†						Credit Facility Agreement, dated as of August 19, 2019, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline, LLC, the lenders party thereto from time to time, the issuing banks thereto from time to time, Natixis, New York Branch, as Credit Facility Agent, and Mizuho Bank (USA), as Collateral Agent (incorporated by reference to Exhibit 10.72 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.66§†						Common Terms Agreement for the Loans, dated as of August 19, 2019, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline, LLC, Natixis, New York Branch, as Credit Facility Agent, Mizuho Bank, Ltd., as Intercreditor Agent, and each other facility agent party thereto from time to time (incorporated by reference to Exhibit 10.73 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

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10.67†						Consent and Amendment to the Common Terms Agreement and the Credit Facility Agreement, dated as of December 28, 2020, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.74 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.68†						Second Amendment to the Common Terms Agreement and Consent to the Credit Facility Agreement, dated as of January 26, 2021, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.75 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.69§†						Consent and Amendment to Credit Facility Agreement, dated as of September 30, 2021, in respect of the Credit Facility Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.76 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.70†						Third Amendment to the Common Terms Agreement, First Amendment to the Common Security and Account Agreement and Consent to the Credit Facility Agreement, dated May 25, 2022, in respect of the Common Terms Agreement, dated as of August 19, 2019, the Common Security and Account Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.77 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.71†						Fourth Amendment to the Common Terms Agreement and Second Amendment to the Credit Facility Agreement, dated as of October 12, 2022, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.78 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.72§†						Fifth Amendment to the Common Terms Agreement and Third Amendment to the Common Security and Account Agreement, dated as of February 27, 2023, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Common Security and Account Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.79 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.73†						Third Amendment to the Credit Facility Agreement, dated as of May 26, 2023, in respect of the Credit Facility Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.80 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.74†						Sixth Amendment to the Common Terms Agreement and Fourth Amendment to the Common Security and Account Agreement, dated as of June 30, 2023, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Common Security and Account Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.81 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.75§†						Seventh Amendment to the Common Terms Agreement and Fifth Amendment to the Common Security and Account Agreement, dated as of October 23, 2024, in respect of the Common Terms Agreement, dated as of August 19, 2019, and the Common Security and Account Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.82 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.76§†						Indenture, dated as of August 5, 2021, by and among Venture Global Calcasieu Pass, LLC, as Issuer, TransCameron Pipeline LLC, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the Issuer’s 3.875% Senior Secured Notes due 2029 and 4.125% Senior Secured Notes due 2031 (incorporated by reference to Exhibit 10.83 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.77§†						First Supplemental Indenture, dated as of November 22, 2021, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline LLC and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of August 5, 2021 (incorporated by reference to Exhibit 10.84 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.78§†						Second Supplemental Indenture, dated as of January 13, 2023, by and among Venture Global Calcasieu Pass, LLC, TransCameron Pipeline LLC and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of August 5, 2021 (incorporated by reference to Exhibit 10.85 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.79§†						Amended and Restated Credit Facility Agreement, dated as of March 13, 2023, by and among Venture Global Plaquemines LNG, LLC, Venture Global Gator Express, LLC, the lenders party thereto from time to time, the issuing banks thereto from time to time, Natixis, New York Branch, as Credit Facility Agent, and Royal Bank of Canada, as Collateral Agent (incorporated by reference to Exhibit 10.86 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.80†						Amended and Restated Common Terms Agreement for the Loans, dated as of March 13, 2023, by and among Venture Global Plaquemines LNG, LLC, Venture Global Gator Express, LLC, Natixis, New York Branch, as Credit Facility Agent, and Royal Bank of Canada, as Intercreditor Agent (incorporated by reference to Exhibit 10.87 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.81†						Amendment No. 1 to the Common Terms Agreement, dated as of September 29, 2023, in respect of the Amended and Restated Common Terms Agreement, dated as of March 13, 2023 (incorporated by reference to Exhibit 10.88 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

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Table of contents


10.82†						Amendment No. 2 to the Common Terms Agreement and Amendment No. 1 to the Common Security and Account Agreement, dated as of May 15, 2024, in respect of the Amended and Restated Common Terms Agreement, dated as of March 13, 2023 (incorporated by reference to Exhibit 10.89 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.83§†						Amendment No. 3 to the Common Terms Agreement, dated as of October 23, 2024, in respect of the Amended and Restated Common Terms Agreement, dated as of March 13, 2023 (incorporated by reference to Exhibit 10.90 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.84†						Indenture, dated as of May 26, 2023, by and between Venture Global LNG, Inc., as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent, relating to the Issuer’s 8.125% Senior Secured Notes due 2028 and 8.375% Senior Secured Notes due 2031 (incorporated by reference to Exhibit 10.91 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.85†						First Supplemental Indenture, dated as of September 25, 2023, by and between Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture dated as of May 26, 2023 (incorporated by reference to Exhibit 10.92 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.86†						Second Supplemental Indenture, dated as of September 28, 2023, by and among Venture Global Commodities, LLC, Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture dated as of May 26, 2023 (incorporated by reference to Exhibit 10.93 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.87§†						Third Supplemental Indenture, dated as of October 24, 2023, by and among Venture Global Commodities, LLC, Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture, dated as of May 26, 2023 (incorporated by reference to Exhibit 10.94 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.88†						Indenture, dated as of October 24, 2023, by and between Venture Global LNG, Inc., as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent, relating to the Issuer’s 9.500% Senior Secured Notes due 2029 and 9.875% Senior Secured Notes due 2032 (incorporated by reference to Exhibit 10.95 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.89§†						First Supplemental Indenture, dated as of November 8, 2023, by and between Venture Global LNG, Inc. and The Bank of New York Mellon Trust Company, N.A., relating to the Indenture dated as of October 24, 2023 (incorporated by reference to Exhibit 10.96 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.90†						Indenture, dated as of July 24, 2024, by and between Venture Global LNG, Inc., as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee and Collateral Agent, relating to the Issuer’s 7.00% Senior Secured Notes due 2030 (incorporated by reference to Exhibit 10.97 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.91§†						Eighth Amendment to the Common Terms Agreement, dated as of March 4, 2025, in respect of the Common Terms Agreement, dated as of August 19, 2019 (incorporated by reference to Exhibit 10.123 to the Registrant’s Annual Report on Form 10-K filed on March 6, 2025)

10.92§†						Indenture, dated as of April 21, 2025, by and between Venture Global Plaquemines LNG, LLC, as Issuer, Venture Global Gator Express, LLC, as the Guarantor, Regions Bank, as Trustee, and each guarantor that may become party thereto from time to time relating to the Issuer’s 7.50% Senior Secured Notes due 2033 and 7.75% Senior Secured Notes due 2035 (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

10.93§†						First Supplemental Indenture, dated as of July 3, 2025, by and between Venture Global Plaquemines LNG, LLC, as Issuer, Venture Global Gator Express, LLC, as Guarantor, and Regions Bank, as Trustee, relating to the Indenture dated as of April 21, 2025 (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.94						Second Supplemental Indenture, dated as of December 9, 2025, by and among Venture Global Plaquemines LNG, LLC, Venture Global Gator Express, LLC, and Regions Bank, relating to the Indenture, dated as of April 21, 2025

10.95§†						Consent and Amendment to the Common Terms Agreement and the Credit Facility Agreement, dated as of May 27, 2025, in respect of the Amended & Restated Common Terms Agreement, dated as of March 13, 2023 and the Amended and Restated Credit Facility Agreement, dated as of March 13, 2023 (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed on August 12, 2025)

10.96§†						Common Terms Agreement for the Loans, dated as of July 28, 2025, by and between Venture Global CP2 LNG, LLC, as Borrower, Venture Global CP Express, LLC and CP2 Procurement, LLC, as Guarantors, MUFG Bank, Ltd., as Credit Facility Agent and Intercreditor Agent, and each other facility agent that may become party thereto from time to time (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.97§†						Credit Agreement, dated as of July 28, 2025, by and between CP2 LNG Holdings, LLC, as Borrower, the several lenders party thereto from time to time and the Bank of Nova Scotia, Houston Branch, as Administrative Agent(incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

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Table of contents


10.98§†						Credit Facility Agreement, dated as of July 28, 2025, by and between Venture Global CP2 LNG, LLC, as Borrower, Venture Global CP Express, LLC and CP2 Procurement, LLC, as Guarantors, the lenders party thereto from time to time, the issuing banks party thereto from time to time, MUFG Bank, Ltd., as Credit Facility Agent, and Sumitomo Mitsui Banking Corporation, as Collateral Agent (incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.99†						Credit Agreement, dated as of September 29, 2025, among Blackfin Pipeline, LLC, as Borrower, Blackfin Pipeline Pledgor, LLC, as Parent, Blackfin Supply LLC, as Permitted Subsidiary, MUFG Bank, Ltd., as Administrative Agent, Sumitomo Mitsui Banking Corporation, as Collateral Agent, and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.100†						Credit Agreement, dated as of September 29, 2025, among Blackfin Pipeline, LLC, as Borrower, Blackfin Pipeline Pledgor, LLC, as Parent, Blackfin Supply LLC, as Permitted Subsidiary, MUFG Bank, Ltd., as Administrative Agent, Sumitomo Mitsui Banking Corporation, as Collateral Agent, and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.101						Ninth Amendment to the Common Terms Agreement, Sixth Amendment to the Common Security and Account Agreement and Fourth Amendment to the Credit Facility Agreement, dated as of October 7, 2025, in respect of the Common Terms Agreement, dated as of August 19, 2019, the Common Security and Account Agreement, dated as of August 19, 2019, and the Credit Facility Agreement, dated as of August 19, 2019

10.102†						Amendment No. 1 to TLA/Revolver Credit Agreement, dated as of October 10, 2025, among Blackfin Pipeline, LLC, as Borrower, Blackfin Pipeline Pledgor, LLC, as Parent, Blackfin Supply LLC, as Permitted Subsidiary, MUFG Bank, Ltd., as Administrative Agent, Sumitomo Mitsui Banking Corporation, as Collateral Agent, and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.103†						Amendment No. 1 to TLB Credit Agreement, dated as of October 10, 2025, among Blackfin Pipeline, LLC, as Borrower, Blackfin Pipeline Pledgor, LLC, as Parent, Blackfin Supply LLC, as Permitted Subsidiary, MUFG Bank, Ltd., as Administrative Agent, Sumitomo Mitsui Banking Corporation, as Collateral Agent, and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q filed on November 11, 2025)

10.104§						Credit and Guaranty Agreement, dated as of November 7, 2025, among Venture Global LNG, Inc., as Borrower, the guarantors party thereto from time to time, the lenders and issuing banks party thereto from time to time, and Sumitomo Mitsui Banking Corporation, as Administrative Agent

10.105†						Management Services Agreement, dated as of December 1, 2014, by and between Venture Global Commodities, LLC and Venture Global Partners, LLC (incorporated by reference to Exhibit 10.98 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.106†						Second Amended and Restated Management Services Agreement, dated as of April 20, 2015, by and between Venture Global LNG, Inc. and Venture Global Partners, LLC (incorporated by reference to Exhibit 10.99 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.107†						Venture Global LNG, Inc. 9.00% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock Certificate of Designations filed with the Secretary of the State of Delaware on September 30, 2024 (incorporated by reference to Exhibit 10.100 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.108#						Venture Global, Inc. 2023 Stock Option Plan (as amended and restated February 9, 2026)

10.109#†						Form of Venture Global, Inc. 2023 Stock Option Plan Non-Qualified Stock Option Agreement (incorporated by reference to Exhibit 10.102 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.110#†						Venture Global, Inc. 2025 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.103 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.111#§†						Executive Employment Agreement, by and between Venture Global LNG, Inc. and Michael Sabel, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.104 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.112#§†						Executive Employment Agreement, by and between Venture Global LNG, Inc. and Jonathan Thayer, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.105 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.113#§†						Executive Employment Agreement, by and between Venture Global LNG, Inc. and Robert Pender, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.106 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.114#§†						Executive Amended and Restated Services Agreement, by and between Venture Global LNG, Inc. and Thomas Earl, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.107 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.115#§†						Executive Employment Agreement, by and between Venture Global LNG, Inc. and Keith Larson, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.108 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

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Table of contents


10.116#§†						Executive Employment Agreement, by and between Venture Global LNG, Inc. and Brian Cothran, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.109 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.117#§†						Executive Employment Agreement, by and between Venture Global LNG, Inc. and Fory Musser, dated as of January 10, 2025 (incorporated by reference to Exhibit 10.110 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.118#†						Form of Restrictive Covenant Agreement (incorporated by reference to Exhibit 10.111 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.119#†						Form of Indemnification Agreement (incorporated by reference to Exhibit 10.112 to the Registrant’s Registration Statement on Form S-1 filed on December 20, 2024)

10.120#†						Form of Venture Global, Inc. 2025 Omnibus Incentive Plan Non-Qualified Stock Option Agreement for Employees, Consultants and Advisers (incorporated by reference to Exhibit 10.115 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.121#†						Form of Venture Global, Inc. 2025 Omnibus Incentive Plan Non-Qualified Stock Option Agreement for Directors (incorporated by reference to Exhibit 10.116 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.122†						F orm of Venture Global, Inc. 2025 Omnibus Incentive Plan Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.117 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.123#†						Form of Venture Global, Inc. 2025 Omnibus Incentive Plan Restricted Stock Unit Agreement for Employees, Consultants and Advisers (incorporated by reference to Exhibit 10.118 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.124#†						Form of Venture Global, Inc. 2025 Omnibus Incentive Plan Restricted Stock Unit Agreement for Directors (incorporated by reference to Exhibit 10.119 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-1 filed on January 13, 2025)

10.125#†						Venture Global, Inc. Director Compensation Policy (incorporated by reference to Exhibit 10.120 to the Registrant’s Annual Report on Form 10-K filed on March 6, 2025)

10.126#†						Venture Global, Inc. Management Incentive Plan (incorporated by reference to Exhibit 10.121 to the Registrant’s Annual Report on Form 10-K filed on March 6, 2025)

19†						Insider Trading Policies and Procedures (incorporated by reference to the Registrant’s Annual Report on Form 10-K filed on March 6, 2025)

21.1						Subsidiaries of the Registrant

23.1						Consent of Independent Registered Public Accounting Firm

31.1						Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2						Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1						Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2						Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

97†						Policy Relating to Recovery of Erroneously Awarded Compensation (incorporated by reference to the Registrant’s Annual Report on Form 10-K filed on March 6, 2025)


†			Incorporated by reference.
#			Indicates management contract or compensatory plan.
§			Portions of this exhibit have been omitted in compliance with Regulation S-K, Item 601(a)(6) and/or Item 601(b)(10)(iv).

189

Schedule I—Condensed Financial Information Financial Information of Venture Global, Inc.

190

VENTURE GLOBAL, INC.

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

BALANCE SHEETS

(in millions)


	December 31,
	2025		2024

ASSETS
Current assets
Cash	$	—	$	—
Total current assets	—		—
Investment in subsidiaries, net	6,742		2,972
Other noncurrent assets	3		7
TOTAL ASSETS	$	6,745	$	2,979

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	1	$	1
Accrued and other liabilities	1		81
Total current liabilities	2		82
Total liabilities	2		82

Equity
Venture Global, Inc. stockholders' equity	6,743		2,897
TOTAL LIABILITIES AND EQUITY	$	6,745	$	2,979

See the accompanying notes to Schedule I.

191

VENTURE GLOBAL, INC.

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF OPERATIONS

(in millions)


	Years ended December 31,
	2025		2024		2023

MANAGEMENT FEE FROM SUBSIDIARIES	$	—	$	—	$	5

OPERATING EXPENSE
General and administrative expense	10		3		2
Total operating expense	10		3		2

INCOME (LOSS) FROM OPERATIONS	(10)		(3)		3

OTHER EXPENSE
Interest expense, net	—		—		(29)
Total other expense	—		—		(29)

LOSS BEFORE INCOME TAXES AND EQUITY INCOME OF SUBSIDIARIES	(10)		(3)		(26)
Less: income tax benefit	(2)		(1)		—
Add: equity in income of subsidiaries, net of income taxes	2,268		1,545		2,707

NET INCOME	$	2,260	$	1,543	$	2,681

See the accompanying notes to Schedule I.

192

VENTURE GLOBAL, INC.

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF CASH FLOWS

(in millions)


	Years ended December 31,
	2025		2024		2023

OPERATING ACTIVITIES	$	(10)	$	(5)	$	6

INVESTING ACTIVITIES
Capital expenditures	—		—		(1)
Net cash used by investing activities	—		—		(1)

FINANCING ACTIVITIES
IPO issuance of Class A common stock	1,750		—		—
Distributions from subsidiaries	143		90		71
Contributions to subsidiaries	(1,680)		—		—
Payments of dividends and distributions	(163)		(80)		(149)
Financing and issuance costs	(75)		(5)		(42)
Issuance of debt	—		—		115
Other financing activities	35		—		—
Net cash from (used by) financing activities	10		5		(5)

Net decrease in cash	—		—		—
Cash at beginning of period	—		—		—
CASH AT END OF PERIOD	$	—	$	—	$	—

See the accompanying notes to Schedule I.

193

VENTURE GLOBAL, INC.

NOTES TO THE CONDENSED FINANCIAL INFORMATION OF PARENT

Note 1 – Basis of presentation

The condensed financial statements represent the financial information required by the Securities and Exchange Commission Regulation S-X 5-04 for Venture Global, Inc. ("Venture Global" or "the Parent Company"). Venture Global was formed on September 19, 2023.

In the condensed financial statements, the Parent Company's investment in subsidiaries are presented at the net amount attributable to Venture Global under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the affiliates are reflected on the condensed balance sheets. The net income or loss from operations of the subsidiaries is reported in equity or loss in income of subsidiaries, excluding income or loss from non-controlling interests. Except for per share amounts, or as otherwise specified, dollar amounts presented within tables are stated in millions.

A substantial amount of Venture Global's operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Venture Global's consolidated financial statements.

Stock Split

On January 27, 2025, the Parent Company effectuated an approximately 4,520.3317-for-one forward stock split (the "Stock Split") of its Class A common stock following the effectiveness of the Parent Company's IPO which was completed on January 27, 2025. All Class A common stock share and per share amounts in these condensed financial statements have been retroactively adjusted to reflect the impact of the Stock Split.

2023 Reorganization Transactions

In September 2023, Venture Global was party to certain reorganization transactions (the "Reorganization Transactions") whereby Legacy VG Partners, a then wholly-owned subsidiary of VG Partners and the controlling shareholder of VGLNG, merged with and into Venture Global (the "2023 Merger"), with VG Partners receiving 2.0 billion shares of Venture Global's Class A common stock in exchange for 100% of its equity interests in Legacy VG Partners. In connection with the Reorganization Transactions, the non-controlling VGLNG shareholders, holding 84,272 shares of VGLNG's issued and outstanding Series C common stock, received 381 million shares of Class A common stock of Venture Global, in a 4,520.3317-for-one exchange for their shares of VGLNG (the "NCI Acquisition"). All prior shares of VGLNG common stock were retired upon completion of the Reorganization Transactions in September 2023. No cash was exchanged as part of the Reorganization Transactions and Venture Global incurred $40 million of third-party transaction costs in connection with its formation and the issuance of its shares of Class A common stock.

The 2023 Merger was accounted for as a transaction between entities under common control. Prior to the 2023 Merger, Venture Global, as a standalone entity, had no operations and had no assets or liabilities. The financial results and other information included in the condensed financial statements for periods prior to the Reorganization Transactions were applied on a retrospective basis and are reflective of Legacy VG Partners.

Note 2 – Investment in Subsidiaries

During the year ended December 31, 2023, prior to the Reorganization Transactions, VGLNG repurchased 5,000 shares of its Series B common stock and 81,896 shares of its Series C common stock for $1.6 billion. VGLNG's repurchase of its outstanding common stock increased Venture Global's controlling interest in the subsidiary to 83.8% and was accounted for as an equity transaction. To reflect this change in ownership interest, the Parent Company recognized a $1.1 billion decrease to investment in subsidiaries for the year ended December 31, 2023.

194

VENTURE GLOBAL, INC.

NOTES TO THE CONDENSED FINANCIAL INFORMATION OF PARENT

After the Reorganization Transactions, Venture Global owned 100% of VGLNG. See Note 1 – Basis of presentation for further discussion.

Note 3 – Equity

IPO and related transactions

On January 27, 2025, the Parent Company completed its IPO in which it issued and sold 70 million shares of Class A common stock, par value $0.01, at a public offering price of $25.00 per share. The Parent Company received proceeds of $1.7 billion, net of underwriting discounts and commissions of $70 million and offering expenses of $10 million. Prior to the completion of the IPO, all shares of Class A common stock held by VG Partners, approximately 1.97 billion shares, were converted into an equal number of shares of Class B common stock.

Preferred and common stock

The Parent Company's Class A common stock has one vote per share and its Class B common stock has ten votes per share. The par value of the Class A common stock and the Class B common stock is $0.01 per share.

As of December 31, 2024, the Parent Company had 1 million shares of preferred stock, 4.5 billion shares of Class A common stock and 1 million shares of Class B common stock authorized for issuance. In connection with the Parent Company's IPO in January 2025, the Parent Company amended and restated its certificate of incorporation and revised the number of shares authorized for issuance. As of December 31, 2025, the Parent Company had 200 million shares of preferred stock, 4.4 billion shares of Class A common stock and 3.0 billion shares of Class B common stock authorized for issuance.

Dividends

During the year ended December 31, 2025, the Parent Company's board of directors declared dividends of $0.03 per share to holders of its outstanding common stock, which were paid during the year ended December 31, 2025 in the aggregate amount of $83 million.

During the year ended December 31, 2024, the Parent Company's board of directors declared the payment of cash dividends to holders of the Parent Company's outstanding common stock in an aggregate amount of $160 million that were paid on a pro rata basis in four equal installments of $40 million over four consecutive calendar quarters on the last business day of each such calendar quarter, commencing on September 30, 2024.

Stock-based compensation

In connection with the Reorganization Transactions, on September 25, 2023, Venture Global adopted the 2023 Stock Option Plan Plan, as amended (the "2023 Plan"), which replaced the 2014 Stock Option Plan (the "Predecessor Plan"). Under the 2023 Plan, all options previously granted and then outstanding under the Predecessor Plan (representing options to purchase 86,664 shares of VGLNG's Series A common stock) were automatically converted, on a 4,520.3317-for-one basis in accordance with and pursuant to the terms of the Predecessor Plan, into options to purchase shares of Venture Global's Class A common stock subject to the terms and conditions of the 2023 Plan. There were no other material differences between the terms and conditions of the 2023 Plan and the Predecessor Plan. Upon its adoption, the 2023 Plan provided for the issuance of approximately 429 million shares of Venture Global's Class A common stock. As noted below, no further awards may be granted under the 2023 Plan.

In connection with the Parent Company's IPO in January 2025, Venture Global adopted the Venture Global, Inc. 2025 Omnibus Incentive Plan (the "Omnibus Incentive Plan"), under which the employees of Venture Global's subsidiaries may receive equity incentive compensation, including stock options, restricted stock units and other awards in the future. As of the effectiveness of the Omnibus Incentive Plan in January 2025, all shares that

195

VENTURE GLOBAL, INC.

NOTES TO THE CONDENSED FINANCIAL INFORMATION OF PARENT

remained available for issuance under the 2023 Plan became available for issuance under the Omnibus Incentive Plan and no further equity awards will be granted under the 2023 Plan. Awards that remained outstanding under the 2023 Plan as of the effectiveness of the Omnibus Incentive Plan will remain outstanding under, and subject to the terms and conditions of, the 2023 Plan. The total number of shares of Class A common stock authorized for issuance under the Omnibus Incentive Plan is approximately 172 million shares, and is subject to annual automatic evergreen increases thereafter.

Note 4 – Supplemental Cash Flow Information

The following table sets forth supplemental disclosure of cash flow information:


	Years ended December 31,
	2025		2024		2023

Accrued dividends and distributions	$	—	$	80	$	—
Venture Global stock-based compensation incurred by subsidiary	22		7		141

196

ITEM 16. FORM 10-K SUMMARY

None.

197

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 2, 2026


VENTURE GLOBAL, INC.
By:			/s/ Michael Sabel
			Name: Michael Sabel
			Title: Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Signature	Title	Date
/s/ Michael Sabel	Chief Executive Officer, Director, Executive Co-Chairman of the Board and Founder (Principal Executive Officer)	March 2, 2026
Michael Sabel
/s/ Robert Pender	Executive Co-Chairman, Director, Executive Co-Chairman of the Board, and Founder	March 2, 2026
Robert Pender
/s/ Jonathan Thayer	Chief Financial Officer (Principal Financial Officer)	March 2, 2026
Jonathan Thayer
/s/ Sarah Blake	Chief Accounting Officer (Principal Accounting Officer)	March 2, 2026
Sarah Blake
/s/ Sari Granat	Director	March 2, 2026
Sari Granat
/s/ Andrew Orekar	Director	March 2, 2026
Andrew Orekar
/s/ Thomas J. Reid	Director	March 2, 2026
Thomas J. Reid
/s/ Jimmy Staton	Director	March 2, 2026
Jimmy Staton
/s/ Roderick Christie	Director	March 2, 2026
Roderick Christie

198

Venture Global - 10-K annual report 2025

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